Condensate Recovery Equipment

What happens if you don’t get water out of your system Corrosion Erosion Loss of efficiency Water Hammer

Subcooled Condensate + CO2 Corrosion Cooled condensate and CO2 form a weak acid that attacks pipes. Subcooled Condensate + CO2 Forms Carbonic Acid ( CO2 + H2O = H2CO3 )

Erosion Water is a steam system removes the protective oxide layer of the pipe wall.

Heat transfers through water less efficiently Loss of Efficiency Heat transfers through water less efficiently

Water Hammer

Water Hammer Show Video

Total Cost of Condensate Condensate Wasted = Money Wasted Wasted Heat = 24.4% Wasted Water = 3.5% Water Treatment Cost = 1.0% Total Waste = 28.9% of steam production cost (Example above is for lost Condensate at 300 psig, 20 bar)

Cost of Lost Heat Sensible Heat = 395 btu/lb, 214 kcal/kg = 32% Latent Heat = 808 btu/lb, 454 kcal/kg = 68% Total Heat = 1203 btu/lb, 668 kcal/kg = 100% Assume total discard of condensate replaced with 50°F, 10°C water Wasted Condensate = 395 btu/lb, 214 kcal/kg Replacement Water = 50 btu/lb, 10 kcal/kg Wasted Heat = 345 btu/lb, 204 kcal/kg 204/668 x 100 = 30.5% of total heat in steam Heat (fuel) = approximately 80% of steam production cost 30.5 x 0.8 = 24.4% of steam production cost lost

PROCESS HEAT TRANSFER and CONDENSATE RECOVERY THE CAUSE AND EFFECT OF VARIOUS DESIGN CONCEPTS

Q = U • A • Δ T Q = HX Design Load (BTU/Hr) U = Manufacturer’s Heat Transfer Value (BTU/ft2/°F/Hr) A = Heat Transfer Surface Area (ft2) DT = (Ts – T2) Approaching Temperature (°F) Ts = Operating Steam Temperature (°F) T2 = Product Outlet Temperature (°F)

Q = GPM • 500 • SG • SH • ΔT Q = HX Performance Load (BTU/Hr) GPM = Product Flow (Gallons/Minute) 500 = 60minutes/hr x 8.32 lbs/gallon (499 actual) SG = Specific Gravity of Product SH = Specific Heat of Product ΔT = Product Temperature Rise (°F)

Q (Design) = Q (Performance) IN THEORY Q (Design) = Q (Performance)

IN REALITY Q (Design) for the heat exchanger will include a factor for fouling and potentially a factor for future requirements. These factors combined usually result in 10-30% additional surface area…possibly higher!!

EXCHANGER VARIABLES Oversurfacing Fouled surface area Non-condensable gases Flooded surface area Variable process inlet and outlet temperatures Variable process flow rates All variables change the BTU demand on the heater, changing the pressure and temperature requirements of the heat transfer media

FOULED SURFACE AREA Decreases the heat transfer efficiency of the tube bundle Inherently causes adjustments in the pressure and/or temperature of the heat transfer media being supplied to the exchanger Resulting in more surface area required…Increasing BTU transfer rate Higher steam pressure from the inlet control valve decreases the efficiency of the heat exchanger. Higher pressure lacks the same heat content of lower pressure. Energy consumption will increase while production levels remain the same

BTU LOSS FROM SCALE SCALE THICKNESS % LOSS BTU 1/16” 13% 1/8” 22% 1/16” 13% 1/8” 22% 1/4” 38% 3/8” 50%

NON CONDENSABLE GASES Non-condensable gases occupy valuable steam space Creates a reduction of heat transfer surface area due to its insulating properties Increases the potential for carbonic acid formation Excessive amount can air-bind the heat exchanger

FLOODED SURFACE AREA Promotes corrosion and fouling Can produce damaging water hammer Decrease the available surface area for heat transfer Poor process temperature control

HEAT EXCHANGER LEVEL CONTROL

LEVEL CONTROL Level control systems flood exchangers to reduce the amount of useable surface area for BTU transfer. Exchangers run flooded due to the control valve on the condensate outlet, modulating to maintain the desired process outlet temperature.

Q = U • A • Δ T Q = Operating Load (BTU/Hr) VARIABLE U = Heat Transfer Value (BTU/ft2/°F/Hr) CONSTANT A = Heat Transfer Surface Area (ft2) VARIABLE DT = (Ts – T2) Approaching Temperature (°F) CONSTANT Ts = Operating Steam Temperature (°F) CONSTANT T2 = Product Outlet Temperature (°F) CONSTANT

LEVEL CONTROL Q = U • A • Δ T

LEVEL CONTROLLED HX Constant High Pressure Steam Supply High Pressure Condensate Return Level Controller Level Controller Valve LEVEL CONTROLLED HX Cold Product In Hot Product Out

LEVEL CONTROL HX This is a common heat exchanger control scheme when high pressure steam (usually superheated and >300psig) is the energy source. It is also used when the condensate load exceeds the capacity of available steam trap designs. Most applications occur in the refining, chemical, and utility industry. Operation: Heat exchange is a function of the level of condensate in the heat exchanger shell (product is in the tubes). Exposed (dry) tubes have a higher “U” (btu/ft²°F) value than flooded (wet) tubes allowing higher transfer of energy from the steam to the product.

LEVEL CONTROLLED HX – HIGH LOAD Constant High Pressure Steam Supply Level Controller Hot Product Out Cold Product In High Pressure Condensate Return Level Controller Valve

LEVEL CONTROL HX – HIGH LOAD HIGH PROCESS HX REQUIREMENT Operation: All tubes exposed (dry) resulting in a high “U” (btu/ft²°F) value than flooded (wet) tubes allowing higher transfer of energy from the steam to the product. “U” value for steam to heavy oil - 70 btu/ft²°F “U” value for steam to molasses - 70 btu/ft²°F “U” value for steam to molten sulfur - 60 btu/ft²°F “U” value for steam to asphalt - 50 btu/ft²°F “U” value for steam to light oil - 90 btu/ft²°F “U” value for steam to watery solution - 225 btu/ft²°F

LEVEL CONTROLLED HX – LOW LOAD Constant High Pressure Steam Supply High Pressure Condensate Return Level Controller Level Control Valve LEVEL CONTROLLED HX – LOW LOAD Cold Product In Hot Product Out

LEVEL CONTROL HX – LOW LOAD LOW PROCESS HX REQUIREMENT Operation: Tubes flooded (wet) resulting in a lower “U” (btu/ft²°F) value than exposed (dry) tubes causing lower transfer of energy from the steam to the product. “U” value for water to heavy oil - 9 btu/ft²°F “U” value for water to molasses - 11 btu/ft²°F “U” value for water to molten sulfur - 8 btu/ft²°F “U” value for water to asphalt - 6 btu/ft²°F “U” value for water to light oil - 20 btu/ft²°F “U” value for steam to watery solution - 120 btu/ft²°F

POTENTIAL PROBLEMS Heavy scaling resulting in loss of heat transfer performance Damaging water hammer Tube sheet failures due to thermal stress Slow reaction to changing process conditions, poor turndown High maintenance on level control valve

HEAT EXCHANGER SUPERHEATED STEAM

SUPERHEAT BOILER

Specific °F SUPERHEATED STEAM PROPERTIES PROPERTIES OF SUPERHEATED STEAM SUPERHEATED STEAM PROPERTIES Specific Volume (cu ft/lb)(%incr) 1.16 1.47(21%) 0.72 0.86(16.3%) 0.91(20.8%) Total Heat¹ (btu/lb)(%incr) 781 884(11.6%) 728 810(10.1%) 871(16.4%) °F 445SAT 600SH 492SAT 700SH Psig 400 650 ¹Total Heat excludes Heat of Saturated Liquid, Sensible Heat

TOTAL SURFACE AREA REQUIRED – 1156 FT² SUPERHEAT EXAMPLE HEAT EXCHANGER – using Saturated & Superheated Steam 650psig@492F(saturated) vs. 650psig@700F(superheated) Heat exchanger requirement – 3,000,000 lbs/hr Heating oil from 300°F to 400°F Heat transfer coefficient (“U” value) for steam to oil – 3.5 btu/ft²·hr·°f (SH) 26.5 btu/ft²·hr·°f (SAT) Calculate surface area required – Superheat(10.6% of total steam energy) Q = U·A·ΔT(LMTD) (3,000,000)(0.106) = (3.5 btu/ft²·hr·°f )(A)(210°LMTD) A = 433 ft² required to absorb superheated steam energy (3,000,000)(0.894) = (26.5 btu/ft²·hr·°f)(A)(140°LMTD) A = 723 ft² required to condense saturated steam energy TOTAL SURFACE AREA REQUIRED – 1156 FT²

SUPERHEAT EXAMPLE HEAT EXCHANGER – using only Saturated Steam 650psig@492F(saturated) Heat exchanger requirement – 3,000,000 lbs/hr Heating oil from 300°F to 400°F Heat transfer coefficient(“U” value) for steam to oil – 26.5 btu/ft²·hr·°(SAT) Calculate surface area required – Saturated Steam Q = U·A·ΔT(LMTD) 3,000,000 = (26.5 btu/ft²·hr·°f)(A)(140°LMTD) A = 809 ft² required to condense saturated steam energy TOTAL SURFACE AREA REQUIRED – 809 FT² 30% less when only utilizing saturated steam

HEAT EXCHANGER-SH Superheated steam is of little value when utilized in heat transfer/heat exchanger applications. It gives up little heat energy until it has cooled to saturation temperature and can utilize the latent heat. Requires larger heat transfer area and sometimes requires larger diameter distribution piping. Creates uneven temperature gradients potentially causing process control problems or fouling of heat exchanger surfaces.

HEAT EXCHANGER STEAM VALVE CONTROLLED HX

STEAM VALVE CONTROLLED HX This is a common heat exchanger control scheme for all steam pressures as the energy source A condensate return system may be required Applications occur in the refining, chemical, and utility industry as well as the food and institutional markets Operation: Heat exchange is a function of the steam pressure and flow through the steam control valve feeding the heat exchanger shell (product is in the tubes). The steam valve modulates (throttles) to maintain variable process heat transfer requirements

Q = U • A • Δ T Q = Operating Load (BTU/Hr) VARIABLE U = Heat Transfer Value (BTU/ft2/°F/Hr) CONSTANT A = Heat Transfer Surface Area (ft2) CONSTANT DT = (Ts – T2) Approaching Temperature (°F) VARIABLE Ts = Operating Steam Temperature (°F) VARIABLE T2 = Product Outlet Temperature (°F) CONSTANT

STEAM VALVE CONTROL Q = U · A · Δ T

VALVE CONTROLLED HX Steam Supply Condensate Return Steam Trap Cold Product In Hot Product Out Modulating Control Valve Temperature Controller

STEAM CONTROL HX PROCESS HX REQUIREMENT Operation: All tubes exposed (dry) resulting in a high “U” (btu/ft²°F) value than flooded (wet) tubes allowing higher transfer of energy from the steam to the product. Control valve modulates (throttles flow) to maintain product heat transfer requirements. “U” value for steam to heavy oil - 70 btu/ft²°F “U” value for steam to molasses - 70 btu/ft²°F “U” value for steam to molten sulfur - 60 btu/ft²°F “U” value for steam to asphalt - 50 btu/ft²°F “U” value for steam to light oil - 90 btu/ft²°F “U” value for steam to watery solution - 225 btu/ft²°F

STEAM VALVE CONTROL Allows the exchanger to run at the lowest possible steam pressure, which maximizes energy efficiency due to latent heat content. Less energy consumed for the same amount of product produced.

ADVANTAGES Minimal scaling or loss of heat transfer surface Longer on-line service life Less damage due to corrosion and thermal stress Quick reaction to changing process conditions, greater turndown Lower overall maintenance

PROCESS DESIGN SUMMARY Utilize all heat transfer surface area Minimize corrosion and fouling by keeping the exchanger dry Eliminate non-condensable gases Quick reaction to changing process conditions, greater turndown By design, utilize the lowest pressure steam possible and gain more latent heat content per pound of steam condensed

Condensate Recovery Systems

Pump Trap Applications Process Heat Exchangers Separators Tank Coils Distillation Columns, pressure and vacuum Condensate Drum – Flash Tanks Open Vented Systems Closed Loop Applications

Condensate Recovery Systems Armstrong’s condensate pumps offer effective recovery of hot condensate Self-actuated, non-electric Condensate pump trap packages

Pump Trap Operation

Mechanical Pumps No seals, motors or impellers which frequently fail Low maintenance Sized for actual condensate load Can be used in closed loop applications Conserve flash steam Returns condensate hotter in closed-loop arrangement which: Reduces likelihood of H2CO3 (carbonic acid) Greater overall efficiency

SELF ACTUATED PUMP OPERATION

Discharge Check Valve-Closed Fill Cycle Motive Valve - Closed Vent Valve - Open Inlet Check Valve-Open Discharge Check Valve-Closed Step 1. During the fill cycle, the motive valve and discharge check valve outlet are closed. The vent valve and inlet check valve are open.

Inlet Check Valve-Closed Pumping Cycle Motive Valve - Open Vent Valve - Closed Inlet Check Valve-Closed Discharge Check Valve-Open Step 2. Float Rises with level of condensate until it passes trip point, and then snap action reverses the positions shown in step one.

Discharge Check Valve-Open End Cycle Motive Valve - Open Vent Valve - Closed Inlet Check Valve-Closed Discharge Check Valve-Open Step 3. Float is lowered as level of condensate falls until snap action again reverses positions.

Inlet Check Valve-Open Discharge Check Valve-Closed Repeat Fill Cycle Motive Valve - Closed Vent Valve - Open Inlet Check Valve-Open Discharge Check Valve-Closed Step 4. Motive Valve and discharge check valve are again closed while vent valve and inlet check valve are open. Cycle repeats.

Motive Pressure Steam, Air, Nitrogen Ensure stable source with negligible variations. Install drip station to insure dry steam is always present at motive pressure valve

Piping Layout to Prevent Hydraulic Shock Discharge pipe from pumps should be connected into the top of return header Flow patterns should be continual – no opposing flows. Check valves should be installed at major elevation changes to disperse hydraulic shock.

Pipe Sizing Discharge piping should be based on 2-3 times the normal condensing rate due to instantaneous discharge rate of the pump. Minimize elevation changes to prevent hydraulic shock. Utilize check valves at main header to minimize backflow.

Understanding and Benefiting from Equipment Stall

Common Problem

Effects of “Stall” Inadequate condensate drainage Water hammer Frozen equipment Corrosion due to Carbonic Acid formation Poor temperature control Control valve hunting (system cycling) Reduction of heat transfer capacity

Factors Contributing to Stall Oversized equipment Conservative fouling factors Excessive safety factors Large operating ranges High back pressure Changes in heat transfer requirements

Solid Solution Pump Trap

Process Heat Exchanger with 100% Turndown Capability

Double Duty Performance DD-12 Trap/Pump combination ASME code carbon steel 200 psig maximum vessel and operating pressure Max 150 psig differential on steam trap 19,900 lb/hr max pumping at 5 psig back pressure Max 93,000 lb/hr trapping at 150 psig differential

3-D view of pump…

Typical package layout… Simplex Design created in 3-D modeling

Mechanical Pump Applications

Vacuum Reboiler Construction Comparison

Hydrocarbon Knockout Drum/Separator

Flare Header Drain

Flash Vessels

Steam Turbine Casing

The End