1. Condensate Recovery Equipment

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

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

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

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

6. Water Hammer

7. Water Hammer
Show Video

8. 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)

9. 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

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

11. 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)

12. 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)

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

14. 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!!

15. 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

16. 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

17. BTU LOSS FROM SCALE SCALE THICKNESS % LOSS BTU 1/16” 13% 1/8” 22%
1/16” %
1/8” %
1/4” %
3/8” %

18. 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

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

20. HEAT EXCHANGER
LEVEL CONTROL

21. 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.

22. 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

23. LEVEL CONTROL
Q = U • A • Δ T

24. 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

25. 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.

26. 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

27. 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 btu/ft²°F

28. 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

29. 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 btu/ft²°F

30. 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

31. HEAT EXCHANGER
SUPERHEATED
STEAM

32. SUPERHEAT BOILER

33. 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

34. TOTAL SURFACE AREA REQUIRED – 1156 FT²
SUPERHEAT EXAMPLE
HEAT EXCHANGER – using Saturated & Superheated Steam
vs.
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

35. SUPERHEAT EXAMPLE HEAT EXCHANGER – using only Saturated Steam
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

36. 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.

37. HEAT EXCHANGER
STEAM VALVE
CONTROLLED HX

38. 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

39. 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

40. STEAM VALVE CONTROL
Q = U · A · Δ T

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

42. 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 btu/ft²°F

43. 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.

44. 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

45. 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

46. Condensate Recovery Systems

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

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

49. Pump Trap Operation

50. 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

51. SELF ACTUATED PUMP OPERATION

52. 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.

53. 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.

54. 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.

55. 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.

56. 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

57. 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.

58. 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.

59. Understanding and Benefiting from Equipment Stall

60. Common Problem

61. 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

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

63. Solid Solution
Pump
Trap

64. Process Heat Exchanger with 100% Turndown Capability

65. 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

66. 3-D view of pump…

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

68. Mechanical Pump Applications

69. Vacuum Reboiler Construction Comparison

70. Hydrocarbon Knockout Drum/Separator

71. Flare Header Drain

72. Flash Vessels

73. Steam Turbine Casing

74. The End