Rules of Thumb for Process Engineers

RULES OF THUMB FOR PROCESS ENGINEERS Revised 8/2002 Edited by H. R. Hunt

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

1

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

6

COMBUSTION ..................................................................................................................6-1

2

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

3

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

4

1 A.

SEPARATION

Vertical 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/ft 2 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: Vg = (11.574) * (AMMcfd) /A

1-1

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. 8. Liquid outlets should have antivortex baffles.

1-2

E.

Solid/Liquid Separations Recommended Feed Solids Content for Separation Processes Feed Solids Content in Vol % Max 25 Max 4 Max 10 Max 0.2 Max 20 Max 15 15-20 40 10 Max 5/10 Max 25 Max 40 25-40 30-50 15-40 10-20 10-30 20-40 20-40 20-40 20-40 2-30 10-40 20-40

Decanter centrifuge Self-cleaning separator Disc-nozzle centrifuge Tube centrifuge Conical hydrocyclone Circulating bed hydrocyclone Tables and spirals Cone concentrator Heavy media cyclone, jigs Clarifiers/thickeners Hydroseparators Bowl classifiers Upstream classifiers Rake/spiral classifiers Filter press Vacuum disc filter Vacuum drum Vacuum band Horizontal filters Sieve bends Vibro screen Basket/peeler centrifuge Pusher centrifuges Screen (scroll) centrifuges Vibro screen centrifuges

F.

20-40

Solid / Liquid Separations Comparative Performance

UNIT OPERATION

FAVORABLE FEED CONDITIONS SOLIDS SOLIDS CONCENTRATION CHARACTERISTICS

CYCLONING

PRODUCT PARAMETER SOLID IN LIQUID IN WASH LIQUID SOLIDS POSSIBILITIES STREAM STREAM FAIR TO GOOD GOOD GOOD FAIR TO POOR LOW EXCELLENT EFFICIENCY FAIR POOR FAIR TO EXCELLENT POOR POOR POOR

SCREENING

POOR

POOR

HIGH/MEDIUM

ULTRAFILTRATION

EXCELLENT

POOR

LOW

FILTRATION SEDIMENTATION CENTRIFUGATION

POOR TO FAIR POOR TO FAIR

1-3

HIGH/MEDIUM MEDIUM/LOW MEDIUM/LOW LOW/MEDIUM

LIGHT, COURSE TO MED. FLOC. FINE DENSE, MEDIUM OR FLOCCULATED FINE DENSE, FINE DENSE, COURSE TO MEDIUM COURSE TO MEDIUM VERY FINE

G.

Brown - Souders Equation For Vessel Sizing W = C DV ( D l − DV ) 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 Dv =

29, 423# / mol 63 psia 520 R x x = 0.333# / ft 3 380.6 ft 3 / mol 14.5 psia 550 R

D1 = 0.82 Sp. Gr. X 62.3 #/Cu. Ft. (H2 0) = 51.0 #/Cu. Ft. W = 1100 .333(51.0 − .333) = 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 Dia . = 43x 4 / π = 7.4Ft. 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.

1-4

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.

1-5

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 Selection of Equipment for a Solid-Liquid Separation Process

1-6

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. 4. Heat Exchanger Velocities

2-1

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 Material

Velocity (FT/SEC)

ADMIRALTY, CARBON STEEL COPPER, BRASS (85-15) NICKEL, COPPER-NICKEL STAINLESS STEEL, MONEL TITANIUM

4 TO 8 2 TO 4 5 TO 10 6 TO 12 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.

2-2

•

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

HOT FLUID

COLD FLUID

WATER AMMONIA MEA OR DEA FUEL OIL FUEL OIL GASOLINE HEAVY OIL HEAVY OIL REFORMER STREAM LIGHT ORGANICS MEDIUM ORGANICS HEAVY ORGANICS GAS OIL GASES GASES CONDENSING STEAM CONDENSING STEAM CONDENSING STEAM CONDENSING STEAM CONDENSING STEAM STEAM LIGHT ORGANICS MEDIUM ORGANICS HEAVY ORGANICS CRUDE OIL GASOLINE (CONDENSING)

WATER WATER WATER WATER OIL WATER WATER HEAVY OIL REFORMER STREAM WATER WATER WATER WATER WATER GASES WATER LIGHT ORGANICS MEDIUM ORGANICS HEAVY ORGANICS PROPANE (BOILING) GASES LIGHT ORGANICS MEDIUM ORGANICS HEAVY ORGANICS GAS OIL CRUDE OIL

2-3

OVERALL U BTU/HR-FT2-F 250-500 250-500 140-200 15-25 10-15 60-100 15-50 10-40 50-120 75-120 50-125 5-75 25-70 2-50 2-25 200-700 100-200 50-100 6-60 200-300 5-50 40-75 20-60 10-40 80-90 20-30

TABLE 2. APPROXIMATE FILM HEAT TRANSFER COEFFICIENTS

LIQUIDS Oils, 20º API 200º F average temperature 300º F average temperature 400º average temperature Oils, 30º API 150 º F average temperature 200º F average temperature 300º F average temperature 400º F average temperature Oils, 40º API 150º F average temperature 200º F average temperature 300º F average temperature 400º F average temperature Heavy Oils, 8-14º API 300º F average temperature 400º F average temperature Diesel oil Kerosene Heavy naphtha Light naphtha180 Gasoline Light hydrocarbons Alcohols, most organic solvents Water, ammonia Brine, 75% water VAPORS Light hydrocarbons Medium HCs, organic sol. Light inorganic vapors Air Ammonia Steam Hydrogen — 100% Hydrogen — 75% (by volume) Hydrogen — 50% (by volume) Hydrogen — 25% (by volume)

SHELL

TUBE SIDE

40-50 70-85 80-100

15-25 20-35 65-75

70-85 80-100 110-130 130-155

20-35 50-60 95-115 120-140

80-100 120-140 150-170 180-200

50-60 115-135 140-160 175-195

20-30 0-50 115-130 145-155 145-155 180 200 250 200 700 500

10-20 20-30 95-115 140-150 130-140

10 psig 25 25 14 13 14 15 40 35 30 25

200 250 200 700 500

Shell or tube sides 50 psig 100 psig 300 psig 60 100 170 70 105 180 30 60 100 25 50 85 30 55 95 30 50 90 105 190 350 80 150 280 70 130 240 55 100 180

VAPORS CONDENSING Steam Steam, 10% non-condensables Steam, 20% non-condensables Steam, 40% non-condensables Pure light hydrocarbons Mixed light hydrocarbons Gasoline Gasoline-steam mixtures Medium hydrocarbons Medium hydrocarbons with steam Pure organic solvents Ammonia

Shell or tube sides 1,500 600 400 220 250-300 175-250 150-220 200 100 125 250 600

LIQUIDS BOILING Water Water solutions, 50% water or more Light hydrocarbons Medium hydrocarbons Freon Ammonia Propane Butane Amines, alcohols Glycols Benzene, tolune

1,500 600 300 200 400 700 400 400 300 200 200

2-4

500 psig 200 220 120 100 110 135 420 340 310 270

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).

TABLE 3 EXCHANGER SERVICE

FOULING (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. Dividedflow TEMA “J” shells with RODbaffle tube bundles are preferred for low pressuredrop, 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

2-5

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 twophase 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 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 hightemperature, sulfur-bearing streams. Austenitic stainless steel alloys are 2-6

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 U-tube exchangers having bundle diameters greater than 36 inches should have Ubend 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

2-7

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 Limit Design Heat Flux < 0.7 Maximum Heat Flux

2-8

NOZZLES

TABLE 4 FLUID

MAXIMUM (Pv 2 ) (LB/FT 2_SEC2)_

SHELLSIDE NOZZLES

CLEAN, NONCORROSIVE, NONABRASIVE SINGLEPHASE GAS, VAPOR, LIQUID

SHELLSIDE NOZZLES

ALL OTHER LIQUIDS

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, NONCORROSIVE NON-ABRASIVE LIQUIDS

6000

TUBESIDE

TWO-PHASE MIXTURES, SATURATED VAPORS, ALL OTHER GASES AND VAPORS

AXIAL NOZZLES WITH PERFORATED DISTRIBUTOR PLATES

2-9

1500

500

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 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 ) • Use Sweep and Long Radius Elbows in Two-Phase Exit Lines 2-10

• •

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 (H d) > Bundle Diameter (Db) • Design Exit Weight Fraction Vapor 0.10 to 0.20 for Hydrocarbons • Maximum Exit Weight Fraction vapor 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.

2-17

§

K.

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 induc ed draft coolers in close proximity and do not locate coolers of different heights in close proximity. 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.

L.

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.

Cooling Towers

2-18

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 qi/di2 = Q/D2 M.

where: Q and qi are volumetric flowrates through the header and branch i, and D and di are the diameters of the header and branch i. Round to nearest standard size.

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.

2-19

Representative Conductivities of Pipe Insulation (Btu/hr·ft·F) Insulation temperature 300º F 400º F (149º C) (204º C)

100º F 38º C

200º F (93º C)

calcium silicate

0.033

0.037

0.041

cellular glass

0.039

0.047

0.055

fiberglass

0.026

0.030

0.034

magnesia, 85%

0.034

0.037

0.041

Polyurethane

0.016

0.016

0.016

500º F (260º C)

600º F (316º C)

0.046

0.057

0.060

0.064

0.074

0.085

0.044

(Multiply Btu-ft/hr-ft 2 -º F by 12 to get Btu in/hr-ft 2 -º F.) (Multiply Btu-ft/hr-ft 2 -º F by 1.7307 to get W / m·K.) (Multiply Btu-ft/hr-ft 2 -º F by 4.1365 x 10-3 to get cal·cm/s·cm2 ·º C.)

Material Asbestos-cement boards Asbestos Kaolin brick Kaolin firebrick Petroleum coke Molded pipe covering Mica Aluminum Iron Steel N.

Thermal Conductivity Btu/hr- ft-°F 0.43 0.090-0.129 0.15-0.26 0.050-0.113 3.4 0.051 0.25 117 30 26

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.

2-20

2.

O.

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.

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.

4.

Heat Transfer From Pipes

2-21

2-22

5.

Typical material emissivities for radiation heat transfer problems Material Aluminum Iron

Steel

Brick Refractory Paint

Polished Oxidized Polished Polished cast New cast Rusted Polished Oxidized Rough plate Poor Good Black matte Black lacquer White lacquer Aluminum

2-23

Emissivity 0.040 0.11-0.19 0.14-0.38 0.21 0.435 0.685 0.52-0.56 0.79 0.94-0.97 0.93 0.65-0.75 0.80-0.90 0.91 0.80-0.95 0.80-0.95 0.27-0.67

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 3. Unit length, diameter, and number of units.

2-24

Start Surface A>150 ft2

Yes

Q Recovery @ T > 1000F

No No Q Removed @ T> 140F

No

Yes

Yes

Exotic Alloy

Yes

Q Recovery Economical

Yes

Yes No Close dT Approach

T > 350F P > 200 psi

Yes

No

No

Yes

Double pipe Exchanger

No

RODBaffle Exchanger

Vibration Low dP

No

Plate Baffle Exchanger

Figure 1 Heat Exchanger Selection

2-25

PlateFrame Exchanger

Air Finned Exchanger

Heavy Duty Finned Surface

Start Fouling Service

Extent of Fouling

Low to Moderately Heavy

Very Heavy

Viscosity Low To Moderately High Very High

Pressure

Less Than Atmospheric

Kettle Reboiler (Finned Tubes) Pump-Through Reboiler

Relatively Clean Service

Fluid Fouling Characteristics

Pump-Through Reboiler (Critical Operations)

Area Required

Greater Than Atmospheric

Small To Moderate

Vertical Thermosyphon Horizontal Thermosyphon

Pump-Through Reboiler

Kettle Reboiler (Finned Tubes)

Figure 2 Reboiler Selection

2-26

Internal Reboiler Vertical Thermosyphon

Large

Kettle Reboiler Horizontal Thermosyphon

Start Corrosive High Pressure

Yes

No Mechanical Cleaning Tubeside Coolant

Yes

Change Design To Reduce Condensing dP

Yes

Very Low Allowable Condensing dP

Use Large Diameter Tubes

Yes

Large Condensing Range

No

Yes Boiling Coolant

Yes Yes

No

No Yes

Internal/ Kettle Reboiler

No

Yes

Vertical E Shell

Shear Control At Exit

Yes

Yes

Large Subcooling

Yes No

Shellside Condensers Horizontal E Shell

No

No

No

No

Low Medium

Temperature Cross

(dP/P) > 0.1

Allowable Condensate dP

Very Low

Low

Large Subcooling

No

Yes

Med-High

Bioling Coolant

ShellSide Condensation Required

No

Horizontal J Shell RODBaffle

Tubeside Condensers Horizontal RODBaffle J Shell

Vetical Downflow Single Pass

Figure 3 Condenser Selection

2-27

Horizontal Single Pass or U Tube

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, 1980pg 118-125) “Guidelines on Fluid Flow systems”, Hydrocarbon Processing, April, 1990. Pg 47-60

2-28

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

2-29

3 A.

TREATING

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 H2 S content of the feed. Catalytic region makes the rest. B. If the acid gas feed is less than 30% H2 S 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

3-1

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

B.

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. 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.

3-2

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 MEA DEA MDEA

Wt% 15 - 20 25 – 30 50 – 55

Rich Loading, M/M 0.30 – 0.35 0.35 – 0.40 0.45 – 0.50

13. Recommended loading in the lean circuit to minimize acid gas flashing are: Amine MEA DEA MDEA

* Total Lean Loading, M/M 0.10 – 0.15 0.05 – 0.07 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:

3-3

Total Dissolved Solids Total Hardness Chlorides Sodium Potassium Iron