RULES OF THUMB
FOR
PROCESS ENGINEERS
Revised 8/2002
TABLE OF CONTENTS
1 SEPARATION ...1-1
A. Vertical Knockout Drum Preliminary Sizing ... 1-1 B. Crude Oil Service Separator Sizing ... 1-1 C. Vertical Separator Design ... 1-1 D. Horizontal Separator Design... 1-2 E. Solid/Liquid Separations ... 1-3 F. Solid / Liquid Separations ... 1-3 G. Brown - Souders Equation For Vessel Sizing ... 1-4 H. Mist Extractor Selection ... 1-4
2 HEAT TRANSFER SHELL & TUBE HEAT EXCHANGERS...2-1
A. Heat Exchanger Design Practices... 2-1 LIQUIDS SHELL TUBE SIDE ... 2-4 B. Reboiler Thermal Design Practices ... 2-8 C. Process Condenser Thermal Design Practices...2-11 D. Heat Transfer Units conversions Table 5 ...2-14 E. Heat Exchangers (General)...2-16 F. Condensers ...2-16 G. Reboilers and Chillers ...2-16 H. Sizing Plate Heat Exchangers...2-17 I. Brazed Aluminum Plate Heat Exchangers ...2-17 J. Air Fin Heat Exchangers ...2-17 K. Fired Heaters ...2-18 L. Cooling Towers...2-18 M. Insulation ...2-19 N. NGL Expander Plants ...2-20
O. Miscellaneous Plant Systems ...2-21 P. Method For Feasibility Study Sizing of Gas Plant Gas/Gas shell & Tube Heat Exchanger: ...2-24
3 TREATING...3-1
A. Dehydration... 3-1 B. Amine Treating ... 3-2 C. Mol Sieve Treating ... 3-4 D. Corrosion ... 3-5 E. Copper Strip... 3-5 F. Conversion Factors ... 3-5 G. Caustic Washer Design ... 3-5 H. Metallurgy Requirements For Amine Treaters... 3-5 I. H2S Gas Toxicity ... 3-7 J. Liquefied Natural Gas (LNG) Plants ... 3-7 K. Gas Treating Iron Sponge ... 3-8 L. Distribution of Sulfur Compounds in NGL Product ... 3-8
4 FLUID FLOW...4-1
A. Misc. ... 4-1 B. NGL Expander Plants ... 4-1 C. Piping ... 4-2 D. Physical Fan Laws ... 4-4 E. Control Valves ... 4-5 F. Two Phase Flow: ... 4-6
5 FRACTIONATION...5-1
A. Minor Components Non Ideal In Hydrocarbons ... 5-1 B. Columns... 5-1
A. Flare... 6-1 B. Fired Heaters ... 6-1 C. Fuel Requirements ... 6-2
7 PHYSICAL PROPERTIES ...7-1
A. Standard Conditions ... 7-1 B. Characterization of Liquid Refinery Feeds and Products ... 7-1 C. Physical Properties of Selected Liquids ... 7-2 D. Physical Properties of Selected Gases/Vapors ... 7-8 E. Physical Properties Recommendations ...7-13 F. Simulation Techniques for Characterization of Oils ...7-14
8 COMPRESSORS, EXPANDERS & PUMPS...8-1
A. Reciprocating Compressors... 8-1 B. Compressor Quickies... 8-1 C. Liquefied Natural Gas (LNG) Plants ... 8-2 D. Energy Conservation Natural Gas Engines... 8-2 E. Fuel consumption... 8-2 F. NGL Expander Plants ... 8-2 G. Gas Processing – Simulation guidelines... 8-3 H. Pump sizing ... 8-3 I. Pumps ... 8-4 J. General:... 8-5
9 REFRIGERATION ...9-1
A. Condensers ... 9-1 B. Propane Refrigeration Systems ... 9-1 C. Gas Processing – Simulation Guidelines ... 9-1 D. Condensing Temperature Effects:... 9-1
10 MISCELLANEOUS... 10-1
A. Large Production & Processing Platforms ...10-1 B. Water and Steam Systems ...10-3 C. Economics ...10-3 D. Hydrates ...10-4 E. NGL Expander Plants ...10-4 F. Miscellaneous Plant Systems ...10-4 G. Liquified Natural Gas (LNG) Plants ...10-4 H. Gas Processing – Simulation Guidelines ...10-4 I. Offshore Pipeline Gas Specifications...10-4 J. Offshore Crude Oil Specifications ...10-5 K. Wind Loadings ...10-5 L. Steam Leaks @ 100 psi...10-5 M. Composition of Air ...10-5 N. Platform Deflection ...10-5 O. Kinetics ...10-6 P. Storage, Vessel Capacity ...10-6 Q. Pipeline Volume:...10-6 R. Pressure Vessels ...10-6 S. NACE Requirements ...10-6 T. Pressure Waves (e.g. water hammer)...10-6 U. Insulation Types ...10-7 V. Absolute Pressure of Atmosphere at Height ‘H’ feet above Sea Level ...10-7
1 SEPARATION
A. Vert ical Knockout Drum Preliminary Sizing
1. Size for Vapor
W=1100 [Density Vapor (Density Liquid-Density Vapor)] 1/2
Where:
W = maximum allowable mass velocity - pounds/hour/ft2
1100 is an empirically determined constant Densities - pounds/cubic foot at process T & P 2. Size for Liquid
Should be able to contain maximum slug expected depending on pipe configuration. Never size for less than 1 minute liquid holdup.
Size 8 to 10 ft tall
B. Crude Oil Service Separator Sizing
1. Use vertical separator for high vapor to liquid ratios and for two phase separation. 2. Use horizontal separator for high liquid to vapor ratios and for three phase separation.
Vessel L/D 3 to 5.
3. Check size for both gas and liquid handling (i.e. gas superficial velocity and liquid residence time).
4. Use 3 min liquid residence time for the hydrocarbon phase in a crude oil system. 5. Use 3 to 6 min residence time for the water phase in a crude oil system.
6. Estimate 15 to 30 minutes water residence time for electrostatic coalescers (100% filled). Vessel L/D 4 to 6.
C. Vertical Separator Design
1. The disengaging space - the distance between the bottom of the mist elimination pad and the inlet nozzle, should be equal to the vessel internal diameter or a minimum of 3' -0".
2. The distance between the inlet nozzle and the maximum liquid level should be equal to one-half the vessel diameter, or a minimum of 2' -0".
3. A mist eliminator pad should be installed. Otherwise the separator should be designed so that actual gas velocity should be no greater than 15% of the maximum allowable gas velocity as calculated by the following equation:
Where: Vg = Vertical velocity of gas, ft/sec
AMMcfd = Actual gas volume at operating conditions, MMcfd
A = Cross Sectional Area of vessel, ft2
4. The dimension between the top tangent line of the separator and the bottom of the mist eliminator pad should be a minimum of 1' -0".
5. Inlets should have an internal arrangement to divert flow downward. 6. Liquid outlets should have antivortex baffles.
7. Mist eliminator pads should be specified as a minimum of 4 inches thick, nominal 9 lb/ft3 density and stainless steel.
8. Normal practice for calculating liquid retention time is to allow for the volume contained in the shell portion of the vessel only. No credit is taken for any liquid retention time attributable to the volume contained in the vessel head. Sump height should be a minimum of 1' -6". to allow for liquid level control.
D. Horizontal Separator Design
The following are commonly used rules of thumb for sizing Horizontal separators. 1. Oil level is usually controlled by a weir, which is commonly placed at a point
corresponding to 15% of the tangent-to-tangent length of the vessel. This results in 85% of the vessel being available for separation. Height of the weir is commonly set at 50% of the internal diameter of the vessel.
2. The maximum liquid level should provide a minimum vapor space height of 1' -3" 3. but not be substantially below the centerline of the vessel.
4. Separators designed for gas-oil- water separation should provide residence time and separation facilities for removal of the water.
5. For separators handling fluids where foaming is considered a possibility, additional foam disengagement space and foam control baffling should be provided. Mist eliminator devices should be located external to the vessel to maximize foam disengagement potential within the vessel.
6. The volume of dished heads should not be taken into account in vessel sizing calculations.
7. Inlet and outlet nozzles should be located as closely as possible to vessel tangent lines.
E. Solid/Liquid Separations
Recommended Feed Solids Content for Separation Processes
Feed Solids Content in Vol %
Decanter centrifuge Max 25
Self-cleaning separator Max 4
Disc-nozzle centrifuge Max 10
Tube centrifuge Max 0.2
Conical hydrocyclone Max 20
Circulating bed hydrocyclone Max 15
Tables and spirals 15-20
Cone concentrator 40
Heavy media cyclone, jigs 10
Clarifiers/thickeners Max 5/10
Hydroseparators Max 25
Bowl classifiers Max 40
Upstream classifiers 25-40
Rake/spiral classifiers 30-50
Filter press 15-40
Vacuum disc filter 10-20
Vacuum drum 10-30 Vacuum band 20-40 Horizontal filters 20-40 Sieve bends 20-40 Vibro screen 20-40 Basket/peeler centrifuge 2-30 Pusher centrifuges 10-40
Screen (scroll) centrifuges 20-40
Vibro screen centrifuges 20-40
F. Solid / Liquid Separations
Comparative Performance
UNIT OPERATION PRODUCT PARAMETER FAVORABLE FEED CONDITIONS
SOLID IN LIQUID STREAM LIQUID IN SOLIDS STREAM WASH POSSIBILITIES SOLIDS CONCENTRATION SOLIDS CHARACTERISTICS FILTRATION FAIR TO GOOD
GOOD GOOD HIGH/MEDIUM LIGHT, COURSE TO
MED. FLOC. FINE SEDIMENTATION FAIR TO
EXCELLENT
POOR LOW
EFFICIENCY
MEDIUM/LOW DENSE, MEDIUM OR
FLOCCULATED FINE
CENTRIFUGATION FAIR POOR FAIR TO
EXCELLENT
MEDIUM/LOW DENSE, FINE
CYCLONING POOR POOR POOR LOW/MEDIUM DENSE, COURSE TO
MEDIUM
SCREENING POOR POOR TO
FAIR
POOR HIGH/MEDIUM COURSE TO
MEDIUM
ULTRAFILTRATION EXCELLENT POOR TO
FAIR
G. Brown - Souders Equation For Vessel Sizing ) ( l V V D D D C W = − W = Vapor Loading - #/Hr. /Sq. Ft.
DV = Vapor Density - #Cu. Ft. at operating condit ion
D1 = Liquid Density - #Cu. Ft.
C = Constant
(a) For Absorbers use 600 (b)For Scrubbers use 1100
(c)For Still use 500
Example: Size Scrubber For Field Engine Discharge
3 / # 333 . 0 550 520 5 . 14 63 / 3 6 . 380 / # 423 , 29 ft R R x psia psia x mol ft mol Dv = = D1 = 0.82 Sp. Gr. X 62.3 #/Cu. Ft. (H20) = 51.0 #/Cu. Ft.
(
51.0 .333)
333 . 1100 − = W = 1100v16.9 = 4520 #/hr./Sq. Ft.Gas Flow = 158,311 MPD x 29.423 #/Mol = 194,000 #/hr. Cross Section Area Required = 194,000 #/hr. = 43 Sq. Ft.
4520 #/hr/Sq. Ft . 4 . 7 / 4 43 . x Ft Dia = π =
Use 8 Ft. Diameter Scrubber H. Mist Extractor Selection
1. The stainless steel mesh pad type mist extractor is generally less expensive than the vane type and is adequate for most clean service applications. Similar liquid removal efficiencies can be achieved (within certain velocity constraints) with mist particle sizes of 10 microns and larger.
2. The pad type usually has less clean pressure drop than the vane type.
3. The vane type usually performs better than the pad type where tacky solids such as iron sulfide are present in the flowing gas stream. The liquid flow from the mist extractor is at right angles to the gas flow in vane type and it tends to wash solids away better.
4. If the vane type is used in corrosive service (hydrogen sulfide, carbon dioxide, or oxygen with water wet gas), the vanes should be 316 stainless steel. Experience has shown that a small amount of corrosion with carbon steel vanes roughs the surface and solids tend to accumulate and plug the vanes rapidly.
5. For retrofit or sometimes new applications, it is possible to use a smaller dia meter vessel for the vane type as it may be fitted in different orientations to limit the velocity to acceptable ranges. The pad type is usually installed horizontally.
6. It is usually cheaper to retrofit vessels with the pad type as both would have to be cut and match marked to fit through an 18” or smaller manway and reinstalled inside the vessel. The vane type usually has boxing that must be welded together inside the vessel while the pad type can usually be bolted.
7. The vane type may be used for small in- line applications where the pad type usually can not.
8. If the pad type plugs with solids or hydrates, the pressure drop will likely dislodge the mist extractor and plug downstream piping or equipment.
9. For tough separation applications where it is necessary to remove mist particles smaller than 10 microns (such as inlet to glycol or amine systems where the foreign liquid may cause foaming or chemical contamination), often a combination of pad type (for coalescing) and vane type (for mist removal) is used.
Separation References
GPSA Engineering Data Book, Vol. 1, Section 7 - Separators and Filters Engineering Standard 10.48-2:
Process Vessel Sizing- Entrainment Reduction SPS Design Report - DR15
2 HEAT TRANSFER SHELL & TUBE HEAT EXCHANGERS
Material presented herein is intended to supplement Phillips Engineering Standards, General Design Specifications, and Recommended Design Practices listed in the Section VI and does not supersede these documents.
A. Heat Exchanger Design Practices
1. Heat Exchanger Selection
The selection logic shown in Fig. 1, at the end of this section, may be used as a guide in selecting heat exchanger types.
2. General Design Practices
General design practices governing the design of shell-and-tube heat exchangers are summarized, as follows:
• High pressure stream should be located on the tubeside.
• Stream requiring special metallurgy should be located on the tubeside.
• Stream exhibiting highest fouling should be located on the tubeside.
• More viscous fluid should be located on the shellside.
• Lower flowrate stream should be placed on the shellside.
• Consider finned tubes when shellside h is less than 30% of tubeside h.
• Do not use finned tubes when shellside fouling is high.
• Design exchanger for maximum utilization of allowable pressure drop.
• Do not design heat exchanger for operation in transition flow.
• Do not provide thermal overdesign by increasing fouling factors.
• Provide thermal overdesign by increasing bundle length, not diameter
• Avoid multiple tubepass exchangers with close temperature approaches.
• Vertical shellside condensation should be in downflow.
• Vertical tubeside boiling should be in upflow.
• Use RODbaffle exchangers when tube vibrations are predicted.
• Use RODbaffle exchangers for low shellside pressure loss processes.
• Avoid triple-segmental plate baffles, disk-and-doughnut baffles, and orifice
baffles.
• Horizontal shellside condensers should be specified with vertically cut baffles.
3. Overall Heat and Film Transfe r Coefficients
Overall heat transfer coefficients suitable for feasibility design estimates are provided in Table 1, and film coefficients are contained in Table 2.
Recommended shellside and tubeside liquid velocities for various tube materials are summarized as follows: Permissible tubeside velocities for dry gases range from 50 to 150 feet/sec. The recommended minimum shellside liquid velocities are 1.5 feet/sec.
TUBE Velocity
Material (FT/SEC)
ADMIRALTY, CARBON STEEL 4 TO 8
COPPER, BRASS (85-15) 2 TO 4
NICKEL, COPPER-NICKEL 5 TO 10
STAINLESS STEEL, MONEL 6 TO 12
TITANIUM 6 TO 15
5. Allowable Pressure Losses
Recommended maximum allowable shellside and tubeside pressure losses are 10 to 15 psi for plate-baffle exchangers. Allowable shellside pressure losses for
RODbaffle should range from 4 to 8 psi. 6. Cooling Water Temperatures
Maximum cooling water and tube wall temperatures to minimize fouling deposition are 125F and 145F, respectively.
7. Mean Temperature Differences
Log Mean Temperature Difference (LMTD) correction factors (F) for single shellpass, multiple tubepass exchangers should be greater than 0.75 to avoid temperature approach problems.
8. Recommended Fouling Factors
Recommended Tubular Exchanger Manufacturers Association (TEMA) fouling factors are provided in Table 3.
9. Vibration Considerations
• Shellside baffle tip and average crossflow velocities should not exceed 80% of
the calculated Connors Critical Velocity in order to avoid fluidelastic instability tube vibration.
• The vortex shedding-to-tube natural frequency ration should not exceed 0.50 to
avoid vortex shedding tube vibration.
• In exchangers flashing gas on the shellside, the turbulent buffeting- to-tube
natural frequency ratio should not exceed 0.50 to avoid turbulent buffeting tube vibration.
• In exchangers where acoustic resonance (noise) is predicted, a triangular tube pitch may eliminate the problem Detuning plates may also be necessary in certain cases.
TABLE 1
OVERALL U
HOT FLUID COLD FLUID BTU/HR-FT2-F
WATER WATER 250-500
AMMONIA WATER 250-500
MEA OR DEA WATER 140-200
FUEL OIL WATER 15-25
FUEL OIL OIL 10-15
GASOLINE WATER 60-100
HEAVY OIL WATER 15-50
HEAVY OIL HEAVY OIL 10-40
REFORMER STREAM REFORMER STREAM 50-120
LIGHT ORGANICS WATER 75-120
MEDIUM ORGANICS WATER 50-125
HEAVY ORGANICS WATER 5-75
GAS OIL WATER 25-70
GASES WATER 2-50
GASES GASES 2-25
CONDENSING STEAM WATER 200-700
CONDENSING STEAM LIGHT ORGANICS 100-200
CONDENSING STEAM MEDIUM ORGANICS 50-100
CONDENSING STEAM HEAVY ORGANICS 6-60
CONDENSING STEAM PROPANE (BOILING) 200-300
STEAM GASES 5-50
LIGHT ORGANICS LIGHT ORGANICS 40-75
MEDIUM ORGANICS MEDIUM ORGANICS 20-60
HEAVY ORGANICS HEAVY ORGANICS 10-40
CRUDE OIL GAS OIL 80-90
TABLE 2. APPROXIMATE FILM HEAT TRANSFER COEFFICIENTS
LIQUIDS SHELL TUBE SIDE
Oils, 20º API 200º F average temperature 40-50 15-25 300º F average temperature 70-85 20-35 400º average temperature 80-100 65-75 Oils, 30º API 150 º F average temperature 70-85 20-35 200º F average temperature 80-100 50-60 300º F average temperature 110-130 95-115 400º F average temperature 130-155 120-140 Oils, 40º API 150º F average temperature 80-100 50-60 200º F average temperature 120-140 115-135 300º F average temperature 150-170 140-160 400º F average temperature 180-200 175-195 Heavy Oils, 8-14º API
300º F average temperature 20-30 10-20 400º F average temperature 0-50 20-30 Diesel oil 115-130 95-115 Kerosene 145-155 140-150 Heavy naphtha 145-155 130-140 Light naphtha180 180 Gasoline 200 200 Light hydrocarbons 250 250
Alcohols, most organic solvents 200 200
Water, ammonia 700 700
Brine, 75% water 500 500
Shell or tube sides
VAPORS 10 psig 50 psig 100 psig 300 psig 500 psig Light hydrocarbons 25 60 100 170 200 Medium HCs, organic sol. 25 70 105 180 220 Light inorganic vapors 14 30 60 100 120
Air 13 25 50 85 100
Ammonia 14 30 55 95 110
Steam 15 30 50 90 135
Hydrogen — 100% 40 105 190 350 420 Hydrogen — 75% (by volume) 35 80 150 280 340 Hydrogen — 50% (by volume) 30 70 130 240 310 Hydrogen — 25% (by volume) 25 55 100 180 270 VAPORS CONDENSING Shell or tube sides
Steam 1,500
Steam, 10% non-condensables 600 Steam, 20% non-condensables 400 Steam, 40% non-condensables 220 Pure light hydrocarbons 250-300 Mixed light hydrocarbons 175-250
Gasoline 150-220
Gasoline-steam mixtures 200 Medium hydrocarbons 100 Medium hydrocarbons with steam 125 Pure organic solvents 250
Ammonia 600
LIQUIDS BOILING
Water 1,500
Water solutions, 50% water or more 600 Light hydrocarbons 300 Medium hydrocarbons 200 Freon 400 Ammonia 700 Propane 400 Butane 400 NOTES:
1. Where a range of coefficients is given for liquids, the lower values are for cooling and the higher are for heating. Coefficients in cooling, particularly, can vary considerably depending upon actual tube wall temperature.
2. Tube side coefficients are based on
3/
4–in diameter tubes. Adjustment to
other diameters may be made by multiplying by 0.75/actual outside diameter. Shell side coefficients are also based upon 3/
4–in diameter. Precise
calculations would require adjustment to other diameters. The accuracy of the procedure does not warrant it. 3. Coefficients can vary widely under any one or combination of the following: a. Low allowable pressure drop. b. Low pressure condensing applications, particularly where condensation is not isothermal.
c. Cooling of viscous fluids particularly with high coefficient coolants and large LMTDs.
d. Condensing with wide condensing temperature ranges — 100º F and larger. e. Boiling, where light vapor is generated from viscous fluid.
f. Conditions where the relative flow quantities on shell and tube sides are vastly different (usually evidenced by difference in temperature rise or fall on shell and tube sides ).
g. Wide temperature ranges with liquids
(may be partly in streamline flow).
Amines, alcohols 300
Glycols 200
TABLE 3
EXCHANGER FOULING
SERVICE (HR-FT2-F/BTU)
LESS 125 F GREATER 125F
COOLING TOWER WATER 0.001 0.002
BRACKISH WATER 0.002 0.003 SEA WATER 0.0005 0.001 BOILER FEEDWATER 0.001 CONDENSATE 0.0005 STEAM 0.0005 COMPRESSED AIR 0.001
NATURAL GAS & LPG GAS 0.001 - 0.002
ACID GASES 0.002 - 0.003
REFORMER FEED-EFFLUENT GAS 0.0015
HYDROCRACKER FEED-EFFLUENT GAS 0.002
HDS FEED-EFFLUENT GAS 0.002
MEA AND DEA SOLUTIONS 0.002
DEG AND TEG SOLUTIONS 0.002
HEAT TRANSFER FLUIDS 0.002
PROPANE AND BUTANE 0.001
GASOLINE 0.002
KEROSENE, NAPTHA, & LIGHT DISTILLATES 0.002 - 0.003
LIGHT GAS OIL 0.002 - 0.003
HEAVY GAS OIL 0.003 - 0.005
HEAVY FUEL OIL 0.005 - 0.007
VACUUM TOWER BOTTOMS 0.010
NATURAL GAS COMBUSTION PRODUCTS 0.005
9. TEMA Shell Configurations
Single shellpass, TEMA “E” shells are preferred for most single-phase and condensing applications. Two shellpass, TEMA “F” shells with two tubepass bundles are preferred when pure counterflow conditions and maximum mean temperature difference (MTD) are required. “F” shell exchangers should be specified with welded longbaffles or “ Lamiflex” longbaffles seals. Bundle should may also be utilized to minimize longbaffle leakage. TEMA “G” and “H” split- flow shells are preferred only for horizontal shellside thermosiphon reboilers. Divided-flow TEMA “J” shells with RODbaffle tube bundles are preferred for low pressure-drop, single-phase and condensing services. TEMA “K” shells are used exclusively for horizontal, kettle reboilers.
10. Return Head Types
Fixed tubesheet exchangers are preferred for services where thermal expansion, shellside mechanical cleaning, and tube bundle removal are not concerns. U-tube
and floating head bundles are required when thermal expansion, shellside mechanical cleaning, and tube bundle removal provisions must be made. Fixed tubesheet exchangers should be considered if shellside-to-tubeside inlet temperature differences are less than 100F. Fixed tubesheet exchangers having shell expansion joints should be avoided. U-tube and floating head exchangers are required when fixed tubesheet units cannot meet above requirements, with U-tube bundles being preferred over floating head bundles if tubeside mechanical cleaning is not required. Split-ring floating head bundles are preferred over pull-through floating head
bundles in general refinery service because of higher thermal performance and lower cost. Outside packed floating head exchangers are not recommended.
11. Shellside Baffle Types
Baffles types recommended for Phillip’s plant services include single-segmental plate-baffles, double-segmental plate-baffles, no-tube-in-window(NTIW) baffles, and RODbaffles. Single-segmental plate baffles, having a single chordal cut, are preferred for single-phase services where higher shellside pressure losses (15 psi) may be tolerated. Double-segmental plate baffles, having two chordal cuts, are preferred for single-phase and condensing services, where modest shellside pressure losses (10 psi) are allowed. RODbaffles are preferred for single-phase and two-phase services, where low shellside pressure losses (5 psi) are required or where flow- included tube vibrations are likely in plate-baffle exchangers. Triple segmental disk-and-doughnut, and orifice baffles are not recommended. NITW baffles may be used as an alternate to RODbaffles where economics are favorable.
12. Tube Type, Size, and Layout
The preferred tube size for shell-and-tube heat exchangers in medium to heavy
tubeside fouling service (.001 hr-ft2-F/Btu or greater) is 1.00 inch O.D. For light
tubeside fouling services (less than .001 hr- ft2-F/Btu), 0.750 inch O.D. tubes are
preferred. Generally 30 or 60 degree triangular layouts are preferred for clean,
single-phase services (<.001 hr- ft2-F/Btu) in which chemical cleaning maybe used.
For medium or heavy fouling services (> .001 hr-ft2-F/Btu) in which mechanical
cleaning is required, 90 square or 45 rotated square layouts are preferred. Minimum TEMA tube pitch-to-diameter ratio is 1.25. For kettle and internal reboiler services and all RODbaffle exchangers, 90 square layout is required.
13. Recommended Material
Tubes: Inhibited Admiralty tubes are strongly recommended for non-chromate containing, cooling water services where tubewall temperatures range from 145F to 450F. Inhibited Admiralty tubes are also recommended for conventionally treated cooling water service for tubewall temperature between 165F and 450F. Do not use admiralty or other copper bearing alloys when cooling tower water may become contaminated with ammonia or where copper is incompatible with the process fluid. Carbon steel tubes are recommended for cooling water services where tubewall temperature is below 165F. Low-chrome steel tubes are recommended for high-temperature, sulfur-bearing streams. Austenitic stainless steel alloys are
recommended for low temperature services (below - 150F). Monel tubes are
recommended for HF acid-containing streams above 160F, while Titanium tubes are recommended for brackish and sea water services. Welded, fully killed carbon steel (ASTM A-214) should be avoided in low pH water soluble hydrocarbons, furfural, phenol, sulfuric acid, amine service, HF alkylation, and in final overhead crude tower coolers. Seamless carbon steel tubes (A-179) should be used where welded tubes are not permitted. Duplex 2205 tubes should be used instead of austenitic stainless tubes in high chloride services. The table below contains recommended tube wall thicknesses.
Material ¾ Inch OD
Wall
Thickness 1 Inch OD
Wall Thickness
Carbon Steel 14 BWG avg wall .083 12 BWG avg wall .109
Non-Ferrous (Inhibited Admiralty)
16 BWG min wall .065 14 BWG min wall .083
Nickel Base Alloy 16 BWG avg wall .065 14 BWG avg wall .083
Ferrous Alloy Steel 16 BWG avg wall .065 14 BWG avg wall .083
Baffles, Tie Rods, & Spacers : should be constructed of minimum quality material compatible with tube and tubesheet material.
Tube Sheets: must be compatible with service conditions. In services requiring welded tube-to-tubesheet joints, strength welds a re preferred over seal welds.
Shell & Channels : must be compatible with service conditions. Specify TEMA “A” type heads when access to the tube ends is desirable or when frequent tubeside cleaning is expected.
Direct question about material suitability should be directed to Engineering Materials and Services.
14. U-Bend Support
tube exchangers having bundle diameters greater than 36 inches should have U-bend tube supports. I designing a new U-tube exchanger, it is preferred to specify a full support baffle at the U-bend tangent, and avoid flowing through the U-bend entirely.
15. Nozzles, Impingement Plates, and Annular distributors
Momentum criteria (pv2) above whic h shellside impingement plates and annular
distributors and tubeside solid distributor plates should be used are summarized in Table 4. Impingement rods can be utilized in lieu of a solid impingement plate. Rod
diameter should be identical to the tube O.D. Perforated impingement plates should not be used.
B. Reboiler Thermal Design Practices
1. Reboiler Selection Logic
The choice of reboiler type is governed by thermal performance, fluid properties, fouling tendencies, and surface area requirements, as shown in the logic diagram provided in Fig. 2 at the end of this section.
2. Internal or Column Reboilers
Internal reboilers, consisting of multi- tubepass, U-tube bundles, should be used for relatively-clean, moderate-viscosity fluids, in small surface-area applications, where periodic column shutdown for cleaning may be tolerated.
Internal Reboiler Recommended Design Practices
• Tube Bundle shall be U-Tube Type
• Tubes Shall be Oriented on 90 Degree Square Pitch
• Minimum Clearance Between Tubes Shall be 0.25 inches
• Tube Bundle Diameter Shall Not Exceed 36 Inches
• Use Two Bundles Side-by-Side in Column for Large Area Requirements
TABLE 4
NOZZLES FLUID MAXIMUM (Pv2) (LB/FT 2_SEC2)_ SHELLSIDE NOZZLES CLEAN, CORROSIVE, NON-ABRASIVE SINGLE-PHASE GAS, VAPOR, LIQUID
1500
SHELLSIDE NOZZLES
ALL OTHER LIQUIDS 500
SHELLSIDE NOZZLES
TWO-PHASE MIXTURES,
SATURATED VAPORS, ALL OTHER GASES AND VAPORS
IMPINGEMENT PLATE OR ANNULAR
DISTRIBUTOR
BUNDLE/SHELL ENTRANCE & EXIT
ALL FLUIDS 4000
TUBESIDE CLEAN,
NON-CORROSIVE NON-ABRASIVE LIQUIDS 6000 TUBESIDE TWO-PHASE MIXTURES, SATURATED VAPORS, ALL OTHER GASES AND VAPORS
AXIAL NOZZLES WITH PERFORATED
3. Kettle Reboilers
Kettle reboilers consisting of multiple tubepass, U-tube bundles, installed inside enlarged TEMA K type shells, are preferred for medium viscosity fluids in moderately heavy fouling services, where large surface areas are required.
Kettle Reboiler Recommended Design Practices
• Tubes Shall be on 90 Degree Square Pitch
• Tube Pitch Depends on Temperature Difference
Temperature Tube Pitch (inch)
Difference ¾” O.D. Tube 1” O.D. Tube
<35F 1.000 1.250
<60F 1.125 1.375
>60F 1.250 1.500
• Shell Diameter (Ds) > 1.6 Bundle Diameter (Db)
• Kettle diameter should be sized for desired liquid entrainment ratio
• Column Liquid Height (Hd) > Bundle Diameter, (Db)
• Weir height (Wh) > Bundle Diameter (Db)
• Use Two Feed & Return Lines for Boiling Range ∆Tbr>100F
• Use Two Feed & Return Lines for Bundle lengths>12 feet
• Limit Design Heat Flux < 0.7 Maximum Heat Flux
• Limit Mixture Wall-to-Bulk Fluid ∆Twb < Half Boiling
Range ∆Tbr
• Use RODbaffle Bundles if Tube Vibration Likely
• Use Small Diameter, Long Tube Length Bundle when practical
4. Vertical Thermosiphon Reboilers
Vertical thermosiphon reboilers, consisting of single-tubepass, single-shellpass, TEMA E shells and having upflow boiling on the tubeside, should be used for
moderate-fouling low viscosity (M< 50 cP), Wide boiling- range (∆Tbr > 100F)
mixtures, at above atmospheric pressures, where moderate surface areas are required.
Vertical Thermosiphon Reboiler Recommended Design Practices
• Single-Tubepass, Single-Shellpass, Fixed Tubepass Exchanger
• Design Exit Weight Fractions Vapor range from 0.10 to 0.15 for Hydrocarbons
• Maximum Exit Weight Fraction Vapor less than 0.30 for Hydrocarbons
• Suited for Wide Boiling Range (∆Tb > 100F), low Viscosity (M< 50cP) Fluids
• Liquid Driving Head (Hd) = 60 to 100% of Tube Length (Lt)
• Liquid Sensible Heating Zone Length (Lsh) < 25% of Tube Length (Lt )
• Exit Pipe Flow area (Apo) ~ (Total Tubeside flow area (At)
• Inlet Pipe Flow area (Api) – 25% of total tubeside Flow Area (At)
• Exit Line Pressure Drop (∆Po) equal to 30% of total Hydrostatic Head (∆Ph)
• Limit Design Heat Flux < 70% of Maximum Nucleate Boiling Heat Flux Pr < 0.2
• Consider inlet tubeside distribution baffles for cases where two-phase process
streams enter exchanger
5. Horizontal Thermosiphon Reboilers
Horizontal thermosiphon reboilers, consisting of multiple-tubepass, U-tube or floating- head RODbaffle bundles, in either TEMA J,G or H shells, should be
considered for viscous fluids, in moderate fouling service, where larger surface areas are required.
Horizontal Thermosiphon Reboiler Recommended Design Practices
• Multiple-Tubepass, U- Tube or Floating Head Design
• Use TEMA H Shell Configuration for Tube Length (Lt)>12 feet
• Column Liquid Driving Heat (Hd) > Bundle Diameter (Db)
• Design Exit Weight Fraction Vapor 0.10 to 0.20 for Hydrocarbons
• Maximum Exit Weight Fraction vapor <0.30 for Hydrocarbons
• Limit Design Heat Flux < 0.7 Maximum Nucleate Boiling Heat Flux
• Tube Diameter-to-Pitch (Dt/Pt) Ratios same as Kettle Reboilers
• Exit Line Pressure Drop (∆Po) < 0.3 Total Hydrostatic Head (∆Ph)
• Use Sweeps and Long Radius Elbows in Two-Phase Exit Piping
5. Forced Circulation Reboilers
Forced circulation reboilers, having vaporization on the tubeside, are recommended for highly viscous fluids in heavy fo uling service, where large surface areas and low exit weight fraction vapor are required.
Forced Circulation Reboiler Recommended Design Practices
• Used for Highly Viscous, Heavy Fouling Fluid Services
• Vertical Tubeside Vaporization Preferred
• Entering Liquid Velocities of 5 to 7 fps
• Design Exit Weight Fraction Vapor from 0.05 to 0.10
• Bubble Flow, Two-Phase Flow Regime Preferred
• Avoid Slug and Stratified Flow in Horizontal Tubeside Reboilers
C. Process Condenser Thermal Design Practices
The major choices to be made in the selection of shell-and-tube condensers used in the petrochemical industry are between shellside and tubeside condensation and between horizontal and vertical orientation.
1. Condenser Selection Logic
Process condenser selection should be go verned by thermal performance, allowable pressure loses, operational pressure, condensing temperature range, condensing
subcooling requirements, as shown in the logic diagram Fig. 3 at the end of this section.
2. Horizontal Shellside condensers
Horizontal TEMA E shellside condensers are preferred for noncorrosive, low
pressure and vacuum service, where the single-phase tubeside cooling medium must be placed in on the tubeside because of high fouling deposition. In low shellside pressure loss services, TEMA J Shell, divided- flow, condensers containing
RODbaffle bundles are preferred. TEMA G shell condensers may be considered in cases where temperature pinch problems occur in E or J type shell. H and K type shells are not recommended for use in horizontal condensers..
Horizontal Shellside Condenser Recommended Design Practices
• Use for Noncorrosive, Low Pressure and Vacuum Service
• Use when Frequent Mechanical cleaning is required
• Limit Shellside Pressure Loss to less than 10% of Inlet Pressure
• Evaluate Effects of Shellside ∆pon MTD for Mixtures
• Use TEMA E Shell if Shellside ∆p Permits
• Use Multiple “E” Shells in Series if Temperature Pinch Predicated
• Use TEMA J Shell with RODbaffle Bundles for Low Pressure Service
• Shell and Baffle Type Governed by Following Shellside∆p:
§ Single Segmental E Shell: ∆ps = 10-20 psi
§ Double Segmental E Shell: ∆ps = 5-10 psi
§ RODbaffle J Shell: ∆ps = 1-5 psi
• Design condenser for Shear Flow Regime
• Use Vertical Baffle Cuts With Drainage Notches
• Vary Baffle Spacing at Exit To Achieve Shear Flow
• Design Outlet Nozzles to Avoid Shellside Condensate Flooding
• Use Separate Exchanger for Condensate Subcooling
3. Vertical Shellside Condensers
Vertical TEMA E Shell downflow shellside condensers are preferred for noncorrosive, low-to-moderate pressure services, where two-phase upflow boiling is occurring on the tubeside.
Vertical Shellside Condenser Recommended Design Practices
• Use for Noncorrosive, Low-to-Moderate Pressure Services
• Use with Two-Phase Boiling on Tubeside
• Use for Close Approach Temperatures
• Preferred for Vertical Thermosiphon Reboilers and Feed-Effluent Exchangers
• Design for Downflow Condensation and Upflow Boiling
• Double Segmental Plate Baffles and RODbaffles Preferred 4. Horizontal Tubeside Condensers
Horizontal tubeside condensers are preferred for kettle and horizontal shellside thermosiphon reboilers and in corrosive services where the condensing medium requires special metallurgy. Multiple tubepass tubeside condensers should be avoided because of potential liquid-dropout and inerts accumulation in floating head channels.
Horizontal Tubeside condenser Recommended Design Practices
• Use in Kettle and horizontal Thermosiphon Reboiler service
• Preferred when Condensing Medium Requires Special Metallurgy
• Limited to Single Tubepass and Two Tubepass U-Tube Designs
• Do Not Design as Multiple Tubepass, Floating Head Unit
• Design for Operation in Shear-Controlled Flow Regime
§
5. Vertical Tubeside Condensers
Vertical TEMA E shell downflow tubeside condensers are preferred for high
pressure, wide condensing range, corrosive fluids, where single-phase fluids are used as cooling medium.
Vertical Tubeside Condenser Recommended Design Practices
• Preferred for High Pressure, Corrosive Condensing Media
• Use with Single-Phase Cooling Medium
• Design as Single Tubepass TEMA E Shell Configuration
• Consider when Inerts Removal is Critical
D. Heat Transfer Units conversions Table 5
MULTIPLY BY TO OBTAIN MULTIPLY BY TO OBTAIN
LENGTH mm 0.039370 in SPECIFIC kj/kg C 0.23885 Btu/lb F
m 3.2808 ft HEAT kcal/kg C 1.0000 Btu/lb F
in 0.083333 ft Btu/lg F 4.1868 kj/kg C
in 25.400 mm THERMAL W/m C 0.57779 Btu/hr ft F
ft 12.000 in CONDUCTIVITY cals/s cm C 241.91 Btu/hr ft F
ft 0.30480 m Btu/hr ft2F/in 0.083333 Btu/hr ft F
AREA m2 10.764 ft2 Btu/hr ft F 1.7307 W/m C cm2 0.15500 in2 kcal/hr m C 0.67197 Btu/hr ft F in2 0.0069444 ft2 W/cm C 57.779 Btu/hr ft F m2/ m 3.2808 ft2/ft DYNAMIC Pa s 2419.1 lb/hr ft ft2/ft 0.30480 m2/ m VISCOSITY cP 2.4191 lb/hr ft ft2 0.092903 m2 kg/hr m 0.67197 lb/hr ft VOLUME m3 35.315 ft3 lb/s ft 3600.0 lb/hr ft In3 0.00057870 ft3 lbf s/ft2 115827.0 lb/hr ft ft3 0.028317 m3 lb/hr 0.00041338 Pa s gal 0.13368 ft3 lb/hr ft 0.41388 cP
gal (IMP) 1.2009 gal (US) KIMEMATIC m2/s 38750.0 ft2/hr litter 0.26417 gal (US) VISCOSITY cSt 0.038750 ft2/hr
MASS kg 2.2046 gal m2/s 10000.0 Stokes lb 0.45359 kg ENERGY kj 0.94782 Btu
FORCE N 0.22481 lbf KWhr 3412.1 Btu
kp 2.2046 lbf kcal 3.9683 Btu
lbf 32.1740 lb ft/s2 ft lbf 0.0012851 Btu
kp 9.80665 N hp hr 2544.4 Btu
PRESSURE Pa 0.0040218 in of water Btu 1.0551 kj
kPa 4.0218 in of water Btu 0.0002931 kWhr
kPa 0.14504 lbf/in2 Btu 0.25200 k cal
kp/m2 0.039441 in of water J 0.00027778 W hr
mm of water 0.09370 in of water POWER W 3.4121 Btu/hr
in of water 0.24864 kPa kcal/hr 3.9683 Btu/hr
in of water 0.036063 lbf/in2 ft lbf/hr 0.0012851 Btu/hr
in of water 0.0024539 atmospheres Hp 2544.4 Btu/hr
VELOCITY m/s 3.2808 ft/s Btu/hr 0.29307 W
m/min 3.2808 ft/min Btu/hr 0.25200 kcal/hr
mi/hr 1.4667 ft/s HEAT FLUX W/m2 0.31700 Btu/hr ft2
ft/s 0.30480 m/s Kcal/hr m2 0.36867 Btu/hr ft2
ft/min 0.016667 ft/s W/cm2 3170.0 Btu/hr ft2
MASS kg/s 7936.6 lb/hr Cal/s cm2 13272.0 Btu/hr ft2
FLOW Btu/hr ft2 3.1546 W/m2
Btu/hr ft2 2.7125 kcal/hr m2
MULTIPLY BY TO OBTAIN MULTIPLY BY TO OBTAIN FLOW lb/s 3600.0 lb/hr RESISTANCE hr m2C/kj 20.442 hr ft2 F/Bt
lb/hr 0.45359 kg/hr hr m2C/kcal 4.8824 hr ft2 F/Bt
VOLUME m3/s 2118.9 ft3/min s cm2C/kcal 0.00013562 hr ft2 F/Bt
FLOW ft3/s 60.000 ft3/min Cm2C/W 0.00056783 hr ft2 F/Bt
ft3/min 0.00047195 m3/s hr ft2F/Btu 0.17611 m2C/W
MASS kg/s m2 737.34 lb/hr ft2 hr ft2F/Btu 0.20482 hr m2C/W
VELOCITY kg/hr m2 020482 lb/hr ft2 HEAT W/m2C 0.17611 Btu/hr ft2F
lb/s ft2 3600.0 lb/hr ft2 TRANSFER kj/hr m2C 0.048919 Btu/hr ft2F
lb/hr ft2 4.8824 kg/hr m2 COEFFICIENT kcal/hr m2C 0.20482 Btu/hr ft2F
DENSITY kg/m3 0.062428 lb/ft3 cal/s cm2C 7373.4 Btu/hr ft2F
g/cm3 62.428 lb/ft3 W/cm2C 1761.1 Btu/hr ft2F lb/in3 1728.0 lb/ft3 Btu/hr ft2F 5.6783 W/m2C lb/ft3 16.018 kg/m3 Btu/hr ft2 4.8824 kcal/hr m2C TEMPERATURE 1.8c + 32 = F (f-32)/1.8 = C C + 273.15 = K F + 459.69 = R METRIC EQUIVALENTS Pa = w/m2 = kg/s2m N = kg m/s2 J = Ws Liter = dm3 Kp = kgt
E. Heat Exchangers (General)
1. Heat Exchanger Area Approx. Area = [Heat Duty, Btu/hr]/[U.LMTD]
Where: U = heat transfer coeff. (GPSA typical U’s Heat Exch.)
2. Limit temperature approach in gas to gas exchanger to 20 °F.
3. For preliminary design for cooling water systems, use a cooling water temperature rise of 15° to 20° F through the heat exchangers. In most cases a process stream temperature approach of 10° F to the cold water to the exchanger is reasonable. 4. If flow through the exchanger is not countercurrent, hot fluid outlet temperature
should be greater than cold fluid outlet temperature.
5. For exchangers of 200 ft2 and less, consider compact heat exchangers.
F. Condensers
1. Be aware when condensing pure components such as propane that the limiting temperature occurs when the desuperheating stops and condensing starts.
2. For water cooling, try to cool no further than a 10° F approach to the warm cooling water leaving the condenser. Use 4 to 8 ft/sec velocity for water through the tubes. Restrict cooling water return temperature to maximum of 125° F.
3. For water cooled propane condenser design, generally use 10° F temperature rise on cooling water through the exchanger.
G. Reboilers and Chillers
1. Many failures occur because the pressure on the condensate return header is higher than the low pressure steam at the reboiler.
2. About 50° F delta T is all that can profitably be used. Limit the approach
temperature of the gas to the refrigerant in gas chillers to 10° F. Less than 10° F delta T requires excess exchanger surface area.
3. Usually design reboilers for a conservative heat flux of 8,000 to 12,000 BTU/ft2 and
reduce pressure of steam to prevent film boiling.
4. Submergence of Bundle – Level generally controlled at top of bundle.
5. For thermosiphon and side reboiler designs for demethanizer columns, limit the vaporization of the reboiler liquid stream to a maximum of about 35% by volume.
Attempting to vaporize more fluid may result in problems with the thermosiphon flow.
H. Sizing Plate Heat Exchangers
A method for calculating plate heat exchangers is presented in “Plate-Type Heat Exchangers” by F. J. Lowry, Chem. Eng., 66, 89-94, June 29, 1959. Generally, accurate sizing of [late heat exchangers must be done by the manufacturer. I. Brazed Aluminum Plate Heat Exchangers
1. For aluminum plate fin reboilers, methanol may tend to accumulate in the reboiler and eventually log off the exchanger limiting thermosiphon flow. It can usually be cleared if a drain is provided on the lower header of the exchanger.
2. Mercury occurring naturally in some natural gas steams is extremely corrosive to aluminum heat exchangers used extensively in LNG plant processes. Plan to check for mercury in feed gas up front in any project.
3. For Aluminum Plate Fin Core- in-Shell evaporator heat exchange design use a 2 to 4 degree temperature approach to shell side evaporating fluid temperature. Use a maximum evaporation of 25% of the thermosiphon circulated fluid in the evaporator when preparing preliminary core specifications.
J. Air Fin Heat Exchangers
1. All air coolers should be designed in accordance with API 661.
2. Normally design for 40° F approach to inlet air temperature if no cooling water used (20° F Minimum).
3. Forced draft units are preferred over over induced draft units.
4. For preliminary estimates assume 4 rows of tubes. Estimate power requirements at 3 HP/MMBTU/hr for fans for face velocity of air to the coil of 450 to 550 ft/min. 5. Limit tip speed of fans:
< 9 feet in diameter to 12,000 ft/min (FPM) >9 feet in diameter to 11,000 ft/min.
6. Hot air recirculation can be a problem, especially in hot weather. Consider air recirculation when locating air Cooled Exchangers.
§ Locate coolers away from taller buildings or structures, especially downwind of the cooler.
§ Do not locate coolers downwind of other heat generating equipment: i.e. furnaces, boilers, etc.
§ Mount coolers high enough from the ground to avoid high inlet air approach velocities. Consider mounting them on pipe lanes or provide at lease ½ a fan diameter clearance between the ground and the plenum.
§ Locate large banks of coolers with the banks long axis perpendicular to the prevailing summer wind direction.
§ Do not mix forced and induced draft coolers in close proximity and do not locate coolers of different heights in close proximity.
K. Fired Heaters
1. Maximum recommended heat flux for a direct fired Triethylene Glycol regenerator
in a TEG Dehydration Unit is 8000 BTU/ft2 of fire tube surface area. The
recommended heat flux for maximum fire tube life is 6000 BTU/ft2.
2. For most process heaters, assume a thermal efficiency of 75 to 80% when calculating fuel requirements.
Where: % Thermal Efficiency = (Heat Transferred/Heat Released)*100. 3. Organic Heat Transfer Fluids
A. Fired heaters for organic heat transfer fluids are usually designed with average radiant heat fluxes ranging from 5000 to 12,000 BTU/hr-sq ft. Actual allowable heat flux is usually limited by fluid maximum allowable film temperature. Film temperature is dependent on:
a. Maximum fluid bulk temperature
b. Velocity of the fluid across the heat transfer surface c. Uniformity of heat distribution in the furnace
d. Heat transfer properties of the heat transfer fluid
B. If too high film temperature results, too much fluid is vaporized and the heat transfer surface is blanketed with vapors. The heat transfer coefficient is rapidly reduced and dangerously high surface temperatures can develop resulting severe fluid degradation and mechanical fa ilure.
C. High surface temperatures may also cause the fluid to carbonize forming carbon
scale on the heat transfer surface which may lead to over heating and tube metal failure.
D. All other things being equal, any organic heat transfer fluid degrades in
proportion to its temperature. Operation at approximately 100° F below vendors maximum recommended bulk fluid operation temperature may extend the life of the fluid by 10 times.
1. The evaporation rate on a cooling tower is dependent on the amount of water being cooled and the temperature differential. For each 10° F temperature drop across the tower, 1% of the recirculation rate is evaporated. In other words, 0.001 times the circulation rate in gpm times the temperature drop equals the evaporation rate in gpm.
2. Windage losses for cooling towers:
Spray ponds 1.0 to 5.0% of circulation Atmospheric Cooling Towers 0.3 to 1.0% of circulation Forced Draft Cooling Towers 0.1 to 0.3% of circulation Evaporation Losses for Cooling Towers:
Evaporation Losses are usually 0.85 to 1.25% of the tower circulation rate. An evaporation loss of 1% of tower circulation per each 10 degrees F temperature drop across the tower can be assumed for estimating purposes.
3. Cooling Water System Feasibility Design:
Feasibility designs for cooling water systems may be completed by setting the water temperature rise across all exchangers, usually 15 to 20 °F rise, (or at a 10 °F
approach to the process outlet temperature if the assumed rise results in a
temperature cross for some exchanger), and setting the inlet water temperature to the exchangers to the site wet bulb temperature plus 8 °F.
4. Cooling Water System Fluid Flow and Piping:
For preliminary sizing branch offs with different flowrates from the main header, the following rule of thumb equations may be used.
D2 = Summation di2 where: Q and qi are volumetric flowrates through
the header and branch i, and D and di
qi/di2 = Q/D2 are the diameters of the header and branch
i. Round to nearest standard size. M. Insulation
1. For estimating insulation thickness:
Thickness = {3 +[(T - 100)]} Truncated / 2 Thickness – inches
T (Process Temperature) – ° F
2. Typical thermal conductivities for insulating materials
The first table below contains recommended insulation conductivities for insulating materials. The second table contain conductivities for various materials.
Representative Conductivities of Pipe Insulation (Btu/hr·ft·F) Insulation temperature 100º F 38º C 200º F (93º C) 300º F (149º C) 400º F (204º C) 500º F (260º C) 600º F (316º C) calcium silicate 0.033 0.037 0.041 0.046 0.057 0.060 cellular glass 0.039 0.047 0.055 0.064 0.074 0.085 fiberglass 0.026 0.030 0.034 magnesia, 85% 0.034 0.037 0.041 0.044 Polyurethane 0.016 0.016 0.016
(Multiply Btu-ft/hr-ft2-º F by 12 to get Btu in/hr-ft2-º F.) (Multiply Btu-ft/hr-ft2-º F by 1.7307 to get W / m·K.)
(Multiply Btu-ft/hr-ft2-º F by 4.1365 x 10-3 to get cal·cm/s·cm2·º C.)
Material Thermal Conductivity
Btu/hr- ft-°F Asbestos-cement boards 0.43 Asbestos 0.090-0.129 Kaolin brick 0.15-0.26 Kaolin firebrick 0.050-0.113 Petroleum coke 3.4
Molded pipe covering 0.051
Mica 0.25
Aluminum 117
Iron 30
Steel 26
N. NGL Expander Plants
1. For thermosiphon reboiler and side reboiler designs for demethanizer columns, limit the vaporization of the reboiled liquid stream to a maximum of about 35% by
volume. Attempting to vaporize more fluid may result in problems with thermosiphon flow.
2. For aluminum plate fin reboilers, methanol may tend to accumulate in the reboiler and eventually log off the exchanger limiting thermosiphon flow. It can usually be cleared if a drain is provided on the lower header of the exchanger.
O. Miscellaneous Plant Systems
1. Cooling Water Systems – For Preliminary design for cooling water systems, use a cooling water temperature rise of 15 to 20° F through the heat exchangers. In most cases a process stream temperature approach of 10 ° F to the cold water to the exchanger is reasonable.
2. For Aluminum Plate Fin Core in Shell evaporator heat exchanger design use a 2 to 4 degree temperature approach to shell side evaporating fluid temperature. Use a maximum evaporation of 25% of the thermosiphon circulated fluid in the
evaporator when preparing preliminary core specifications.
3. Wind Chill & Tw = 33-[(10.45+10 V ) (33-T)]/32
Heat Loss H = (10.45+10 V – V)(33-T)
Where: Tw = Wind chill temp. °C T = actual temp.
V = wind speed in meters/sec.
H = heat loss in kcal/m2-hr.
5. Typical material emissivities for radiation heat transfer problems Material Emissivity Aluminum Polished 0.040 Oxidized 0.11-0.19 Iron Polished 0.14-0.38 Polished cast 0.21 New cast 0.435 Rusted 0.685 Steel Polished 0.52-0.56 Oxidized 0.79 Rough plate 0.94-0.97 Brick 0.93 Refractory Poor 0.65-0.75 Good 0.80-0.90
Paint Black matte 0.91
Black lacquer 0.80-0.95
White lacquer 0.80-0.95
P. Method For Feasibility Study Sizing of Gas Plant Gas/Gas shell & Tube Heat Exchanger:
1. From the process simulator output for the process, determine the required UA rate for the gas/gas exchanger.
Assume U = 60 BTU/Hr Ft °F A = UA = UA
U 60
Assume a 20 ft long exchanger with ¾” OD tubes on a 15/16” triangular pitch.
Go to a Tube Count Table and read the number of tubes required for the Area A and unit diameter and/or number of units.
You now have a feasibility estimate which includes:
1. Exchanger Area (Ft2)
2. Number of ¾” tubes
Surface A>150 ft2 Q Recovery @ T > 1000F Q Removed @ T> 140F Q Recovery Economical Exotic Alloy T > 350F P > 200 psi Close dT Approach Yes No Yes Yes No Double pipe Exchanger Heavy Duty Finned Surface Air Finned Exchanger No No No Yes Yes Vibration Low dP No Yes Plate-Frame Exchanger Plate Baffle Exchanger RODBaffle Exchanger Yes Yes No No Figure 1 Heat Exchanger Selection
Fluid Fouling Characteristics Viscosity Area Required Extent of Fouling Relatively Clean Service Very High Low To Moderately High Fouling Service Pump-Through Reboiler Large Very Heavy Low to Moderately Heavy Pressure Vertical Thermosyphon Horizontal Thermosyphon Kettle Reboiler (Finned Tubes) Kettle Reboiler (Finned Tubes) Pump-Through Reboiler (Critical Operations) Less Than Atmospheric Greater Than Atmospheric Figure 2 Reboiler Selection Pump-Through Reboiler Internal Reboiler Vertical Thermosyphon Kettle Reboiler Horizontal Thermosyphon Small To Moderate Start
Corrosive High Pressure Allowable Condensate dP Mechanical Cleaning Tubeside Coolant ShellSide Condensation Required Allowable Condensing dP Internal/ Kettle Reboiler (dP/P) > 0.1 Yes No No Medium Change Design To Reduce Condensing dP No Yes
Med-High VeryLow
Yes Horizontal E Shell Yes No Yes Figure 3 Condenser Selection Boiling Coolant Shear Control At Exit Yes Large Subcooling No No Large Condensing Range Very Low Low Yes Bioling Coolant Large Subcooling No No No Temperature Cross
Low Use LargeDiameter
Tubes Yes Vertical E Shell Horizontal J Shell RODBaffle Horizontal RODBaffle J Shell Shellside Condensers Vetical Downflow Single Pass Horizontal Single Pass or U Tube Tubeside Condensers Yes No No Yes No Yes Yes Yes Start
HEAT TRANSFER REFERENCES
Kern, D. Q., Process Heat Transfer, McGraw-Hill, 1950
Tabork, J. et. al, Heat Exchangers, Theory & Practice, McGraw-Hill, 1981 Phillips Eng. Std. 10.44-2, Shell & Tube Process Design Criteria
Phillips Eng. Std. 10-44-3, Reboiler Characteristics & Selection Phillips Eng. Std. 15.18-4, Shell & Tube Mechanical Design Criteria Phillips Eng. Std. 15.18-5, RODbaffle Heat Exchanger Specifications
Phillips Engineering Standard 15.18-2, Air Cooled Heat Exchanger Mechanical Design Criteria Phillips Engineering Standard 25.04-85, General Design, shell and Tube Heat Exchangers, Mechanical Fabrication Requirements
Phillips Engineering Standard 25.04-89, Heater-Fired-Mechanical Design Specifications
Perry, R. H., Chemical Engineers Handbook, Section 11, 4th Ed. 1963
HTRI Design Manuals, Vol. I & II.
Premises for Design & Specification of Shell & Tube Heat Exchangers, 1992
Gas Processors Suppliers Association Engineering Data Book, Tenth Edition, 1987; Volume I, Sections 8, 9, & 10
Standards of the Tabular Exchanger Manufacturers Association, Seventh Edition, 1988 API Standard 660, Fifth Edition (to be issued in 1993), Shell- And-Tube Head Exchanger for General Refinery Services
API Standard 661, Third Edition, April 1992, Air-Cooled Heat Exchanger for General Refinery Services
“Quick Calculation of Cooling Tower Blowdown and Makeup”, Chemical Engineering, July 7, 1975, pg 110
“Designing a Near Optimum Cooling- Water System”, Chemical Engineering, April 21, 1980- pg 118-125)
HEAT TRANSFER REFERENCES (CONTINUED)
The Randall Corporation process group used this method for preliminary estimates and reports close match to their final design
“Organic Fluids for High Temperature Heat-Transfer Systems” W. F. Seifert, and L. L. Jackson, Chemical Engineering, October 30, 1972, pg 95-104
3 TREATING
A. Dehydration
1. Dehydrate gas to 60% of the saturation water content at the conditions of lowest saturation.
Sulfur Recovery Units
A. Thermal zone will produce 55-65% of the sulfur and is a function of the H2S
content of the feed. Catalytic region makes the rest.
B. If the acid gas feed is less than 30% H2S then flame stability in the reaction
furnace is a potential problem. Minimum temperature for effective operation is 1700° F.
C. Temperature in catalyst beds should be kept below 800° F.
D. SRU steam production will be approximately 6700 lbs of steam per long ton of sulfur produced.
E. Glossy carbon deposits on catalyst indicates amine carryover.
F. Sulfur fog is caused by too much cooling capacity. Sulfur mist can be caused by excessive velocity in the condenser.
G. Ferrules should extend at least 6” inside the tubesheet. Refractory lining is usually 2 12 - 3" thick on the tubesheet.
H. Mass velocity in waste heat exchanger and sulfur condenser tubes should be 2-6 lbs/sec-ft2.
I. Space velocity through catalyst beds should be 700-1000 SCFH of gas per cubic foot of catalyst. Lean streams, lower value and rich streams, higher value.
J. Sulfation of catalyst caused by SO3. Oxygen combines with SO2 to form SO3
which is chemisorbed on alumina surface.
K. Velocity in process piping should not exceed 100 ft/sec.
L. Liquid sulfur solidifies at 246° F and becomes very viscous above 320-350° F M. Approximate Stack Gas Flow, scfm:
SGF = (Sulfur Production, LT/D) x (100) 2. Glycol Dehydration
a. TEG – Dew point depression ranges 80-140° F. Degree of dehydration which can be obtained depends on amount of water removed from glycol in the reboiler & circulation rate. Minimum circulation rate to assure good glycol gas contact is
approx. 2 gal. glycol for each pound of water to be removed. Max is ≈7 gal. and
standard is ≈3 gal.
b. Stripping Gas-Approx. 3-8 scf/gas of glycol circ.
c. Glycol will absorb ≈1 scf of gas/gallon of glycol. Glycol contactor – For best
scrubbing of overhead gas install “Mist Pad” on the face of “Vane Type” mist extractor.
d. Estimate total reboiler duty from 2000 BTU/US gal of TEG circulation rate. Note that the use of glycol/glycol heat exchangers will reduce the total reboiler duty. e. Estimate glycol loss from 0.1 gal TEG/MMSCF.
f. Packing-Minimum of 4’ in any gas-glycol contactor.
g. Triethylene Glycol Dehydration Unit-Maximum recommended heat flux for a direct fired TEG regenerator is 8000 BTU/square foot of fire tube surface area.
The recommended heat flux for maximum fire tube life is 6000 BTU/ft2.
3. Trouble shooting
Black, viscous solution indicates that heavy hydrocarbons have been carried over with the gas. Sweet, burnt sugar smell accompanied by low pH and a dark, clear solution signals that thermal degradation is occurring.
B. Amine Treating
1. Amine Circulation: 3 cu.ft acid gas/gal amine
Reboiler Steam Rate: ≈1.2 lbs steam/gal amine
MEA gpm = 41.0 * Q*X/Z
DEA gpm = 45.0 * Q*X/Z (conventional) DEA gpm = 32.0 * Q*X/Z (high load)
Where Q = Gas, MMscfd
X = Acid Gas, volume percent Z = Amine Concentration, wt.%
2. Max acid gas pickup not more than 0.35 mols/mol of MEA. Normal value around 0.3.
3. Amine treating processes tend to be troubled by the same problems regardless of the type amine used.
4. Typical MEA losses due to entrainment: Absorber: 1.0 #/mmscf
Still: 2.5 #/mmscf
5. Flow Velocity – Rich Stream: Not to Exceed 5 fps Lean Stream: Not to Exceed 7 fps 6. Filter Beds: Recommended flow rate through carbon bed
4 gpm/ft2 (cross sectional area)
≈ 20 minutes superficial contact time
7. Loadings: .36 mols CO2/mol MEA [absorber RICH] .12 mols C02/mol MEA [still LEAN] 8. Reflux Ratio: MEA & DEA 1.5 to 3.0
[mols H20/mols acid gas leaving reflux drum] 9. Equivalent Steam Rate:
MEA 0.9 to 1.2 lbs steam/gal amine
DEA 0.8 to 1.1 lbs steam/gal amine
10. Lean amine can contain 0.05 to 0.08 mols total acid gas and still meet specs. 11. CO2 and H2S gases appreciably increase total water content and dehydration
requirements of gas streams.
12. Recommended maximum ranges for amine strength and acid gas loadings that have proven historically to adequately address corrosion concerns are:
Amine Wt% Rich Loading, M/M
MEA 15 - 20 0.30 – 0.35
DEA 25 – 30 0.35 – 0.40
MDEA 50 – 55 0.45 – 0.50
13. Recommended loading in the lean circuit to minimize acid gas flashing are:
Amine * Total Lean Loading, M/M
MEA 0.10 – 0.15
DEA 0.05 – 0.07
MDEA 0.004 – 0.010
* These loadings should be easily achieved with a 1.0-2.0 M/M stripper reflux ratio.
14. Recommended Minimum Water Quality Standards for Make- up Water fo r Amine Plants:
Total Dissolved Solids <100 ppm
Total Hardness <3 grains/gal
Chlorides <2 ppm
Sodium <3 ppm
Potassium <3 ppm
Iron <10 ppm
15. Liquid/Liquid Contactors: (Feasibility Sizing Data)
For rough diameter sizing of liquid/liquid contactors fo r amine treating of light hydrocarbon liquids, use 12 to 15 GPM of hydrocarbon per square foot of packed tower cross section area. This should correspond to approximately 10% of flooding velocity.
For hydrocarbon distributor nozzles for liquid/liquid contactors, use an orifice velocity of approximately 1 ft/sec. Higher velocities than this can lead to emulsion problems. Velocities lower than 0.5 ft/sec can result in NGL being entrained in the sour amine stream.
To estimate height of packing required, assume 6 to 8 ft of packing for each theoretical separation stage.
Mercaptan Removal from Gas
MEA & DEA will remove approx.: 40-55 mol% methylmercaptan 20-25 mol% ethylmercaptan 0 –10 mol% propylmercaptan
Regenerative Caustic process will remove mercaptans down to <10 ppm. Activated Carbon, Calgon FCA, will remove 4-5 wt% mercaptans. C. Mol Sieve Treating
1. Bed Design (Length/Diameter)
Minimum Maximum
Liquid L/D 3:1 5:1
Gas L/D 2:1 4:1
2. Max. Gas Velocity: 0.33 to 0.75 ft/sec
(superficial linear velocity)
3. Max. Liquid Velocity: 50 bbls/hr/ft2 (bed area)
4. Min. Velocity: Liquid: 60 sec contact time, or
0.01 psi/ft ∆p (liquid).
Gas: 3.5 sec (gas)
5. Mol Sieve – Draining bed leaves approx. 25 vol% of total bed volume on bed as sponged liquid.
6. Alumina – Draining bed leaves approx. 0.048 gals. per pound of alumina on bed as sponged liquid.
7. Molecular Sieve Dehydrators – As strictly a rule of thumb based on many Phillips designs, when the pressure drop through a mol sieve bed reaches 20 psi, the bed support is nearing its maximum load capacity and action should be taken to reduce the pressure drop.
D. Corrosion
1. C02 Corrosion: Low Corrosion – Pco2 < 7 psia
Possible High Corrosion - Pco2 ≈7-15 psia
High Corrosion – Pco2 > 15 psia Where: Pco2 = Partial Pressure of C02 2. Corrosion rate directly related to temperature.
E. Copper Strip
Copper Strip Test ASTM 5.05 D1838
No. 1A copper strip normally < 1-2 ppm H2S.
H2S corrosive to copper strip≈ 1ppm or .16 gr/100 scf. Copper
Strip will not detect Mercaptan or other Organic Sulfides. F. Conversion Factors
H2S & C02 factors
1 mol% H2S = 630 grains/100 scf 1 mol% C02 = 813 grains/100 scf
Grains of H2S/100 scf x 1.591 x 10 = Mol% H2S 1 MMscf H2S = 37.6 long tons sulfur
1 grain H2S/100 scf = 17.1 ppmw = 22.8 mg/m 1 grain H2S/100 scf = 15.9 ppmv
1 grain C02/100 scf = 12.3 ppmv
H2S ppmw = [gr. H2S/100 scf] x [542/(mol wt gas)] G. Caustic Washer Design
Vertical washers sized by using a factor of 400-500 gal/hr/sq.ft. of cross-sectional area of empty tower. In the tower, 5-7 ft. of raschig rings equal 1 stage.
1. Vessels
a. Amine contactor, flash tank, stripper, surge tank, accumulator, inlet scrubber, and outlet scrubber shall be carbon steel and stress relieved with corrosion allowances as shown in 1.C.
b. Trays for the contractor and stripper should be 304 stainless. c. Corrosion Allowances for MEA and DEA Systems
C02/H2S<20 C02/H2S>20 Inches Inches Inlet Scrubber 1/8 1/8 Amine Contactor 1/8 1/8 Outlet Scrubber 1/16 1/16 Flash Tank 1/8 1/8 Cross Exchanger 1/8 1/8 Amine Stripper 3/16 3/16 Reflux accumulator 1/8 1/4 Reboiler 1/8 1/8 Reclaimer 1/4 1/4 Surge Tank 0 0 Piping 1/16 1/16 Amine Cooler* 1/8 1/8
Stripper Overhead Condenser* 1/8 1/4
*Corrosion allowance applies to shell side exchangers with water cooling in the tubes.
2. Heat Exchangers
a. Shells – carbon steel and stress relieved
b. Tubes – 12 gauge minimum, carbon steel, seamless
c. Reclaimer element – carbon steel, 2- inch schedule 80 tubes. Amine temperature in reclaimer should not exceed 310° F.
d. Temperature of amine in reboiler should not exceed 250° F. e. U-bends of U-tube carbon steel bundles shall be stress relieved. 3. Pumps
a. The amine circulation and stripper reflux pumps shall be carbon steel with 316 stainless trim.