project shihab

Project title

A DESIGN OF A 312 MT/DAY METHANOL PLANT FROM NATURAL GAS

Project definition:

A Methanol plant is to be set up at Birashar,Brahmanbaria in Bangladesh having a capacity

of 312 MT 99.49%(wt%) Methanol per day, corresponding to 112320 MT of 99.49% (wt%)

Methanol per year (360 stream day per year), and an important by product 46.872 MT/day of

96.88 % (wt%) methanol per stream day corresponding to 16874 MT of 96.88% (wt%)

Methanol per year (360 stream day per year) including all offsites, auxiliaries, utilities and

supporting facilities using Natural gas (96.48% CH4) from near byTitas Gas Field as feed stock.

Specification of Raw material:

a.Natural gas from Titas gas field

Natural gas specification on the basis of methane composition

Constituents Composition(mol%)

Methane 96.48

Ethane 1.60

Propane 0.35

i-Butane 0.10

n-Butane 0.08

i-pentane 0.05

n-pentane 0.04

n-Hexen 0.05

n-Heptane 0.19

CO2 0.72

N2 0.35

Total 100

b. Steam

Steam specification

100% pure superheated steam

Specification of product

conditions

Mass flow rate(ton/day) 312

Temperature(oC) 118.3

Pressure(kPa) 607.9

Aqueous fraction 1

Composition (Mass fraction)

CH3OH(Methanol) 0.995

H2O(Water) .005

Properties

Mass density(Kg/m3) 688.5

Heat capacity(KJ/Kg-C) 4.134

Vapor phase fraction 0

Viscosity(cP) 0.1853

Specific Heat(KJ/Kg-mole-C) 126.7

Surface tension(dyne/cm) 19

By product

a.Specification of 96.88 % CH3OH

conditions

Mass flow rate(ton/day) 46.87

Aqueous fraction 1


CH3OH(Methanol) 0.968

CO2 0.031

b. Specification of fuel gas

conditions

Mass flow rate(ton/day) 6.9

Aqueous fraction 0


C-1 0.137

C-2 0.020

C-3 0.008

n C-4 0.011

i C-4 0.009

nC-5 0.025

iC-5 0.021

nC-6 0.090

nC-7 0.688

Utilities

Electric power requirement:3.27×1013 kW electric power is required for pumping the process

fluid and to run the compressors,columns,heater etc.

Water requirement:19888.8 ton/day water.

Air requirement:15926.4 ton/day

Liquid propane requirement : 2116.6 ton/day

Plant location

Brahmanbaria/Birashar

Latitude =23.97o

Longitude =91.11o

Area

Total area required for the plant is m2( acres) and required for processing unit is m2( acres)

Design Basis

Design basis includes site conditions,utilities, raw materials etc.which influence the process

design and the design of individual unit,equipment or facility of the overall project.Design basis

in the present context is different from that one defines in stoichiometry.Design basis here is to

be considered as conditions in existence with which to design the project.

Important design basis includes :

Geological Data

Climate Conditions

Utility Conditions

Structural Design

Raw Materials

Others

Geological Data

Geological data includes:

a.Site characteristics

Flood level: 5 m (max.)

Tidal level: 4.54 m(max.)

Ground water level: 3 m

Height from sea level:10 m

b. Soil type

Corrosion tendency : lightly corrosive

c.Seismic condition

Load bearing capacity: The seismic load coefficient for the plant area is 0.38.

Climate Condition

a.Design condition for equipment or facility

I. Process equipment: Summer day (dry bulb temperature =40oC, Wet bulb

temperature =40oC, avg .relative humidity =90% ); winter day(dry bulb temperature

=12oC )

b.Design conditions for building

I. HVAC : summer day (maximum dry bulb =40oC, wet bulb =40oC)

Winter day (minimum dry bulb temperature =12oC)

II.Ventilation : summer day (maximum dry bulb =40oC)

Winter day (minimum dry bulb temperature =12oC)

c.Meteorological conditions :

I. Ambient temperature

Maximum = 40oC

Avg. daily maximum =38oC

Avg. monthly maximum =40oC

Average =28 oC

Avg. daily minimum =22 oC

Avg. monthly minimum =12 oC

Minimum =21 oC

II.Humidity

Relative humidity =80%

III.Rainfall

Avg. annual rainfall =3499.2 mm

Maximum monthly rainfall =1089.9 mm(July)

Maximum daily rainfall =405 mm

Maximum hourly rainfall =60 mm

Maximum intensity (in a 15 minute period)=108 mm/hr

Design intensity =100 mm/hr

IV. Barometric pressure (at sea level)

Minimum pressure =101253 pa

V. Wind velocity

Maximum recorded wind velocity = 199.8 km/hr

Design velocity =210 km/hr

Utility Condition

a.Raw water

I. Source:filtered water from titas river

II. Supply pressure : as per water treatment plant intake requirement

III. Supply temperature : 32oC

IV. TDS :149 ppm

V. Total hardness : 89 as gm (CaCO3)

VI. Total sulfate : 18 as gm (SO42-)

VII. PH : 7.0

VIII. Maximum alkalinity : 61 as gm (CaCO3)

IX. Total dissolved SiO2 :5.9 ppm

X. Total iron : 0.88 as gm (Fe2+)

b. air

I. Instrument air : as per instrument requirement condition

Raw materials

a.Natural gas from Titas gas field

Natural gas specification on the basis of methane composition

Constituents Composition(mol%)

Methane 96.48

Ethane 1.60

Propane 0.35

i-Butane 0.10

n-Butane 0.08

i-pentane 0.05

n-pentane 0.04

n-Hexen 0.05

n-Heptane 0.19

CO2 0.72

N2 0.35

Total 100

b. Steam

Steam specification : 100% pure superheated steam

Other Information:

Natural catastrophe: A possibility of storm in the months of April-May.

Value of by-products: No economically feasible by-products are obtained.

Process Selection

1. Natural gas Sweetening: Amine Process: Chemical absorption processes with aqueous alkanolamine solutions are used for

treating gas streams containing hydrogen sulfide and carbon dioxide. However, depending on the

composition and operating conditions of the feed gas, different amines can be selected to meet

the product gas specification. Amines are categorized as being primary, secondary, and tertiary

depending on the degree of substitution of the central nitrogen by organic groups. Primary

amines react directly with H2S, CO2, and carbonyl sulfide (COS). Examples of primary amines

include monoethanolamine (MEA) and the proprietary diglycolamine agent (DGA). Secondry

amines react directly with H2S and CO2 and react directly with some COS. The most common

secondary amine is diethanolamine (DEA), while diisopropanolamine (DIPA) is another

example of a secondary amine, which is not as common anymore in amine-treating systems.

Tertiary amines react directly with H2S, react indirectly with CO2, and react indirectly with little

COS. The most common examples of tertiary amines are methyldiethanolamine (MDEA) and

activated methyldiethanolamine. Processes using ethanolamine and potassium phosphate are now

widely used. The ethanolamine process, known as the Girbotol process, removes acid gases

(hydrogen sulfide and carbon dioxide) from liquid hydrocarbons as well as from natural and

from refinery gases. The Girbotol treatment solution is an aqueous solution of ethanolamine,

which is an organic alkali that has the reversible property of reacting with hydrogen sulfide

under cool conditions and releasing hydrogen sulfide at high temperatures. The ethanolamine

solution fills a tower called an absorber through which the sour gas is bubbled. Purified gas

leaves the top of the tower, and the ethanolamine solution leaves the bottom of the tower with the

absorbed acid gases. The ethanolamine solution enters a reactivator tower where heat drives the

acid gases from the solution. Ethanolamine solution, restored to its original condition, leaves the

bottom of the reactivator tower to go to the top of the absorber tower, and acid gases are released

from the top of the reactivator.

2. Natural Gas Liquid recovery: Choosing a cost-effective NGL recovery technology requires

consideration of a broad range of factors (Mehra and Gaskin, 1999). The main variables that

affect the choice of the most cost-effective process for a given application include inlet

conditions (gas pressure, richness, and contaminants), downstream conditions (residue gas

pressure, liquid products desired, and liquid fractionation infrastructure), and overall conditions

(utility costs and fuel value, plant location, existing location infrastructure, and market stability).

In addition to the feed gas composition and

operation mode, the most decisive technical characteristics of any process are the feed gas

pressure and permissible unit pressure drop. The following guidelines have been suggested for

the selection of a NGL recovery process (Brands and Rajani, 2001).

1. In case of sufficiently high pressure, the self-refrigeration process requires the lowest capital

investment. However, if the pressure differential between feed gas and treated gas is insufficient,

additional compression is required.

2. When the feed gas pressure is close to the treated gas pressure, over a large pressure drop

range, it may be more economical to employ a cryogenic refrigeration process.

3. When the feed gas pressure is clearly below the required pipeline pressure, it is usually most

economical to apply mechanical refrigeration with additional compression to remove heavy

hydrocarbons instead ofcompression followed by the self-refrigeration process. This is due to the

fact that compressors are capital intensive equipments.

4. When the feed gas pressure is equal to or lower than the required pipeline pressure, solid bed

adsorption seems a good option, as it is quick to start up and is robust against changes in the feed

gas composition and flow rate. Generally the solid bed process is only practical for gas that has

small amounts of heavy hydrocarbons. Richer gases require refrigeration. It is clear that the solid

bed adsorption process will usually be competing against the self-refrigeration process.

Specially, the solid bed adsorption unit is operated at lower differential pressure compared to

selfrefrigeration and thus no additional compression is required. In fact, at low feed gas pressure

and for strict dew point specifications, economical analysis favors the solid bed adsorption

process. With reference to the membrane application to control the hydrocarbon dew point, there

is no clear judgement. Current discussions look at this on a point-by-point base and compare the

economics with other processes.The window of opportunity is still to be seen, although its use in

lean fuel gas is more common.

3. Methane to Methanol conversion process

Catalytic Conversion

Features:

Conversion of methane to methanol with an economic yield of 10% In most experiments with solid catalysts, selectivities to methanol fell rapidly as methane

conversions exceeded 59% complete oxidation of methane to carbon dioxide (ΔH = -877 kJ/mol) is highly favored

over partial oxidation of methane to methanol (ΔH = -200 kJ/mol) A noticeable progress, however, has been made in the field of molecular catalysis by

Periana et al., who demonstrated the selective conversion of methane to methanol at temperatures around 473 K over platinum bipyrimidine complexes. According to their experiment, 81% selectivity to methyl bisulfate, a methanol derivative, was reached at methane conversion of 90% in concentrated sulfuric acid

Although these results are promising, commercial applications are hampered by difficult separation and recycling of the molecular catalyst.

Thermal Cracking

Methane is converted to methanol by partial oxidation to hydrogen gas and carbon monoxide (synthesis gas or syngas) at high temperatures normally several hundred degrees celsius

Syngas is then catalytically converted to methanol over a copper or platinum surface, also at a couple hundred degrees Celsius

It is only around five or ten percent efficient due to accidental total oxidation to carbon dioxide and water.

Photo-Catalytic Conversion

Ultraviolet light breaks water into a hydrogen and hydroxyl free radical, which are highly reactive. When a hydroxyl radical reacts with a methane molecule, a hydrogen is displaced and methanol is produced.

With the use of tungsten oxide or a similar semiconductor, photons of lower energy than ultraviolet (down to blue) can be used.

Using Of WO₃ as photo-catalyst visible laser light can be used in room temperature It is highly energy inefficient (only 2-3% efficiency) The process is not out in commercial production yet

Biological conversion

Conversion combines both methane and ammonia streams using methane-oxidizing bacteria and ammonia-oxidizing bacteria, in both wild type and genetically modified forms

Can convert heterogeneous methane feedstocks, unlike existing commercial process Does not require a pure source of methane It does not require expensive chemical catalysts Cleanup and dehumidification processes not required Widely applicable to digester gas, landfill gas, peatbogs, marshes, and wastewater

treatment facilities Conversion process is time consuming

ICI process

Catalyst: Copper-Zinc oxide catalyst Temperature: 200-30000C Pressure: 5-10 MPa Activity of this catalyst is more sensitive to impurities (poisoning) Reduced manufacturing costs.

Process description

1. Natural gas Sweetening: The general process flow diagram for an amine-sweetening plant varieslittle, regardless of the

aqueous amine solution used as the sweetening agent (Figure 7-2). The sour gas containing H2S

and/or CO2 will nearly always enter the plant through an inlet separator (scrubber) to remove

any free liquids and/or entrained solids. The sour gas then enters the botto of the absorber

column and flows upward through the absorber in intimate countercurrent contact with the

aqueous amine solution, where the amine absorbs acid gas constituents from the gas stream.

Sweetened gas leaving the top of the absorber passes through an outlet separator and then flows

to a dehydration unit (and compression unit, if necessary) before being

considered ready for sale. In many units the rich amine solution is sent from the bottom of the

absorber to a flash tank to recover hydrocarbons that may have dissolved or condensed in the

amine solution in the absorber. The rich solvent is then preheated before entering the top of the

stripper column. The amine–amine heat exchanger serves as a heat conservation device and

lowers total heat requirements for the process. A part of the absorbed acid gases will be flashed

from the heated rich solution on the top tray of the stripper. The remainder of the rich solution

flows downward through the stripper in countercurrent contact with vapor generated in the

reboiler. The reboiler vapor (primarily steam) strips the acid gases from the rich solution. The

acid gases and the steam leave the top of the stripper and pass overhead

through a condenser, where the major portion of the steam is condensed and cooled. The acid

gases are separated in the separator and sent to the flare or to processing. The condensed steam is

returned to the top of the stripper as reflux. The lean amine solution from the bottom of the

stripper column is pumped through an amine–amine heat exchanger and then through a cooler

before being introduced to the top of the absorber column. The amine cooler serves to lower the

lean amine temperature to the 100◦F range. Higher temperatures of the lean amine solution will

result in excessive amine losses through vaporization and also lower acid gas-carrying capacity

in the solution because of temperature effects.

2. Natural gas liquid recovery:

When insufficient pressure is available to attain the required dew point with the self-refigeration

process, cryogenic refrigeration can be considered. Cryogenic refrigeration processes

traditionally have been used

for NGL recovery. These plants have a higher capital cost but a lower operational cost The inlet

gas is first cooled in the high-temperature, gas-to-gas heat exchanger and then in the propane

chiller. The partially condensed feed gas is sent to a separator. The liquid from the separator is

fed to the demethanizer, and the gas is cooled further in the low-temperature gasto- gas

exchanger and fed into a second cold separator. Gas from the cold separator expands through the

expansion turbine to the demethanizer pressure, which varies from 100 to 450 psia. The turbo

expander simultaneously produces cooling/condensing of the gas and useful work, which may be

used to recompress the sales gas. Typically 10 to 15% of the feed gas is condensed in the cold

separator, which is usually at −30 to −60◦F. The expander lowers the pressure from the inlet gas

value (600 to 900 psia) to the demethanizer pressure of 100 to 450 psia. Typical inlet gas

temperatures to the demethanizer are −130 to −150◦F, sufficiently

low that a great deal of the ethane is liquefied. The demethanizer is a low temperature distillation

column that makes a separation between methane and ethane. Methane and components lighter

than methane, such as nitrogen, are the principal products in the vapor near the top of the

column, whereas ethane and heavier components, such as propane, butanes, and heavier

hydrocarbons, comprise the principal components in the bottom product of the column. The

molar ratio of methane to ethane in the bottom product is typically 0.01 to 0.03. Because the

outlet of the expander is usually two-phase flow, the liquid produced in the expander serves as

reflux for the demethanizer (Elliot et al., 1996). The bottom product from the demethanizer can

be fractionated further to produce pure product streams of ethane, propane, butanes, and natural

gasolin. The bottom product temperature is often below ambient so that feed gas may be used as

the heat transfer medium for the reboiler. This provides additional refrigeration to the feed and

yields higher ethane recovery, typically 80% (Holm, 1986). The top product from the

demethanizer, after heat exchange with the inlet gas, is recompressed to pipeline pressure.

3. Methanol synthesis section

A mixture of CO, H2, and CO2 is produced by steam reforming , a process in which natural gas

and steam are mixed and reacted in a reformer operated at 1.6MPa .Natural gas consist of 99%

methane and rest inerts. In the present process , steam and natural gas are fed to the reformer in a

ratio of 3:1.The reformer consists of an arrangement of vertical tubes filled with nickel-

impregnated ceramic catalyst. Rows of these tubes are located inside an insulated firebox, where

they are heated by the combustion of natural gas. The natural gas and steam that are blended to

become the reformer feed enter the process at 300C and 210oC , respectively. The mixture is

preheated to 450 0C by exhaust gas from the firebox, and it is introduced to the reformer through

a header that distributes the mixture evenly among the parallel reformer tubes . Two key

reactions occur: the steam-reforming reaction itself,

CH4 + H2O CO + 3H2 and the water gas shift reaction CO +H2O CO2 + H2

The product gas leaves the reformer at 8550C and 1.6 MPa.

Energy efficiency in the steam reforming is improved by recovering heat from the burner exhaust

gas , which leaves the firebox at 960 0C. The exhaust gas is cooled in a series of heat-exchange

operations that preheat the reformer feed streams to 4500C , produce superheated steam at 4.8

MPa and 1000C superheat from the boiler feedwater at 300C, and preheat the combustion air to

3000C. The superheated steam is used to drive turbines elsewhere in the process or it can be

exported , for example to generate electricity. The burner exhaust gas leaves the heat-recovery

units and enters a stack at 1500C for release to the atmosphere.

The product gas leaving the reformer contains water that should be removed to reduce the

amount of gas that must be compressed and to minimize the impact on subsequent conversion of

CO to methanol. Heat is removed from the gas by generating superheated steam (at 4.8MPa ,

1000C superheat), cooling the gas to 15 0C above the temperature of the generated steam. Then ,

three steps occur in recovering heat , concomitantly, reducing the water content: first, heat

recovery for use elsewhere in the process control; second, cooling by ambient air in an air cooler;

and third, use of cooling water to reduce the temperature of the synthesis gas to 350C. Condensed

water is separated from the gas in each of these steps and collected in a condensate drum. With

much of the water now removed, the product can properly be referred to as synthesis gas. The

make-up gas (MUG) compressor increases the pressure of the synthesis gas from 1.6 MPa to 7.5

MPa in two stages , so that it can be injected into the converter loop. Between compressor stages,

cooling water is used to reduce the temperature of the gas to 1000C, and any condensate formed

is removed. The compressed synthesis gas is introduced into the converter loop, where it is

combined with recycle gas.

The converter loop consists of a recycle compressor , whose primary purpose is to provide the

pressure required for the gas to flow through the system, the methanol synthesis reactor (MSR) ,

heat exchangers , a methanol condenser , and a gas-liquid separator (flash drum). The mixture

that is to become the feed to the MSR consists of recycle gas and fresh synthesis gas. After the

recycle gas and fresh synthesis gas are blended, the mixture flows through the recycle

compressor and then is heated to 130C 0C by a partially cooled product stream leaving the MSR.

The recycle compressor is sized to circulate the recycle stream at a rate that is 7.8 times the rate

at which fresh synthesis gas is fed to the converter loop. The blended recycle-fresh feed mixture

leaving the heat exchanger following the compressor is split into two streams : one, containing

30% of the mixture , is sent to another heat exchanger where its temperature is raised to 220oC

by a fraction of the product stream from the MSR and injected into the first stage of the MSR :

the remaining 70% , which is still at 1300C , is injected at various location along the MSR.

The key reactions in the MSR are :

CO2 + 3H2 CH3OH + H2O

CO + 2H2 CH3OH

The product gas leaving the MSR is partially cooled by being split into two streams each of

which passes through a heat exchanger before being recombined ; one is used to heat the feed

stream to the first stage of the MSR to 2200C , and the other passes through a waste –heat

recovery unit. The recombined product stream is cooled further in an air-cooled exchanger

before being brought to 350C by cooling water. At 350C ,a liquid consisting of the condensed

methanol and dissolved gases is separated from the gas stream in a flash drum and sent to a

methanol purification column. The uncondensed gases are split , with a portion being purged

from the system and the remainder forming the recycle gas that is blended with fresh synthesis

gas to form the feed to the recycle compressor. After the condensed crude methanol is recovered

in the high pressure separator, it is sent to a methanol purification column. Typically, methanol

purification requires two columns, one to remove the light ends ( mainly by-products generated

in the methanol synthesis reactor such as dimethyl ether and dissolved gases ) and another to

separate methanol and water and any other by-products with a lower volatility than methanol.

Specification- grade methanol (99% mole fraction) is recovered as the overhead product of the

heavy ends column and sent to storage.

Process block diagram for natural gas processing

(a) CO2 removal process

Liquid

Separator

Absorber

Flash

tank

Lean-rich

Heat exchanger Regenerator

MEA

pump

Reflux

Accumulator

Recycle

pump

Sour gas

Sweet gas

Fuel Gas

Lean MEA

Rich MEA

Acid gas

Make-up MEA

(b) NGL recovery process

Gas to Gas

Heat exchanger

Propane chiller

Separator

Gas to Gas heat exchanger

Cold Separator

Expander

Demethanizer

Compressor

Sweet gas

Processed gas

NGL product

Process Block diagram for methanol production

Primary

Reformer

Secondary

Reformer

Water Gas

Shift Converter

Condenser

&

Separator

Gas Separator

Preheater

Methanol

Synthesis Reactor

Re

Compressor

Distillation

Column

Natural gas

Steam

Combustion air

Synthesis gas

WSGDSG

Converter gas

Purge gas

Condensate

Methanol

Waste water

Product Mixture

Recycle

Process Flowsheet

D 110

20

6

H 113

78

E13 0

9

D 120

19

E11 2

4

11

10

E12 1

13

14

15

L123

16

L124

12

17

18

VLV 114

E21 1

2221

E21 2

24

44

25

26

E21 4

27

37 29

G 216

33

32

E21 7

34

30

E21 8

31

D 210

36

38

43

E22 1

39

G 220

40

G 220A

41

42

45

VLV 312

46

E31 3

48

R 310

50

R 32051

E32 1

52

54

55

47

R 330

53

49

104

Q 314

105

E1

E33 1

56

R 330A

57

106

107

E41 1

58

59

60

H 421

61

62

63

E43 1

66

65

6467

68

69

75

G 440

70

H 451

71

73

72

74

103

B84

76

G 511

77

78

94

G 512

79

E51 3

80

82

83E51 6

92

95

81

R 510

96

E51 4

84

E51 5

86

87

88

89

90

91

97

VLV 611

98 D 610

100 D 620

101

99

102

35

H 1111

3

2

H 122

H 213

H 410

H 420

H 430

H 450B11

E51 7

93

H 215

Material and Energy balance

1.

MS2

1993 kmol/h

Methane 96.65%

Ethane 1.6%

Propane 0.35%

i-Butane 0.10%

n-Butane 0.08%

i-Pentane 0.04%

n-Pentane 0.03%

n-Hexane 0.03%

n-Heptane 0.06%

CO2 0.72%

Nitrogen 0.35%

@25℃, 7000kPa

MS1

2000 kmol/h

Methane 96.48%

Ethane 1.6%

Propane 0.35% MS3

i-Butane 0.10% 7 kmol/h

V-100

n-Butane 0.08% Methane 46.72%

i-Pentane 0.05% Ethane 3.71%

n-Pentane 0.04% Propane 1.06%

n-Hexane 0.05% i-Butane 0.86%

n-Heptane 0.19% n-Butane 1.07%

CO2 0.72% i-Pentane 1.6%

Nitrogen 0.35% n-Pentane 1.91%

@25℃, 7000kPa n-Hexane 5.75%

n-Heptane 36%

CO2 0.83%

Nitrogen 0.04%

@25℃, 7000kPa

2.

MS4 (@25℃, 7000kPa) MS5 (@46.35℃, 7000kPa)

7450 kmol/h 1500 kmol/h

MEAmine 100% Methane 97.35%

MS2 Ethane 0.18%

1993 kmol/h MEAmine 0.0045

Methane 96.65% CO2 0.40%

Ethane 1.6% Nitrogen 0.45%

Propane 0.35%

i-Butane 0.10% MS6

n-Butane 0.08% 7943 kmol/h

i-Pentane 0.04% Methane 5.86%

n-Pentane 0.03% Ethane 0.06%

n-Hexane 0.03% Propane 0.08%

n-Heptane 0.06% i-Butane 0.02%

CO2 0.72% n-Butane 0.02%

Nitrogen 0.34% i-Pentane 0.01%

@25℃, 7000kPa n-Pentane 0.008%

n-Hexane 0.0075%

n-Heptane 0.016%%

MEAmine 94%

CO2 0.11%%

Nitrogen 0.0007%

@45.5℃, 7000kPa

3.

E-100

MS7

280.5 kmol/h

Methane 97.35%

Ethane 1.2%

Propane 0.25%

i-Butane 0.04%

n-Butane 0.03%

i-Pentane 0.009%

n-Pentane 0.005%

n-Hexane 0.002%

n-Heptane 0.002%

CO2 1.1%

Nitrogen 0.02%

MEAmine 0.009%

@44.73℃, 3000kPa

MS6

7943 kmol/h

Methane 5.85%

Ethane 0.06% MS8

Propane 0.08% 7662 kmol/h

V-101

i-Butane 0.02% Methane 2.5%

n-Butane 0.02% Ethane 0.02%

i-Pentane 0.01% Propane 0.08%

n-Pentane 0.008% i-Butane 0.02%

n-Hexane 0.0075% n-Butane 0.02%

n-Heptane 0.015% i-Pentane 0.01%

CO2 0.11% n-Pentane 0.0085%

Nitrogen 0.0007% n-Hexane 0.008%

MEAmine 94% n-Heptane 1.6%

@45℃, 7000kPa CO2 0.07%

MEAmine 97.23%

@44.73℃, 3000kPa

4.

MS 11 MS 4


MEAmine 100% MEAmine 100%

@234.9℃, 7000kPa @45℃, 7000kPa

5.

E-101

MS 10 MS 11


MEAmine 100% MEAmine 100%

@263℃, 7000kPa @235℃, 7000kPa

MS 8 MS 9


Methane 2.5% Methane 2.5%

Ethane 0.02% Ethane 0.02%

Propane 0.08% Propane 0.08%

i-Butane 0.02% i-Butane 0.02%

n-Butane 0.02% n-Butane 0.02%

i-Pentane 0.01% i-Pentane 0.01%

n-Pentane 0.0085% n-Pentane 0.0085%

n-Hexane 0.008% n-Hexane 0.008%

n-Heptane 1.6% n-Heptane 1.6%

CO2 0.07% CO2 0.07%

MEAmine 97.23% MEAmine 97.23%

@44.73℃, 3000kPa @82.22℃, 1000kPa

6.

E 100

MS 14

7450 kmol/h MS 10

MEAmine 100% 7450 kmol/h

@263℃, 7000kPa MEAmine 100%

@263℃, 7000kPa

MS 15

0.4275 kmol/h

MEAmine 100% @25℃, 7000kPa

7.

MS 9 MS 12


Methane 2.5% Methane 46%


Propane 0.08% Propane 1.5%







MIX-100

T-101

CO2 0.07% CO2 1.26%

MEAmine 97.23% MEAmine 49%

@82.22℃, 1000kPa @228.3℃, 1000kPa

MS 20 MS 13


Methane 0.07% MEAmine 100%

Ethane 0.004% @260.4℃, 1000kPa

Propane 0.048%

i-Butane 0.02%

n-Butane 0.03%

i-Pentane 0.03%

n-Pentane 0.03%

n-Hexane 0.065%

n-Heptane 0.32%

CO2 0.006%

MEAmine 99.37%

@25.3℃, 1000kPa

T-101

8.

MS 16 MS 12


Methane 46% Methane 90.68%


Propane 1.5% Propane 3%







CO2 1.26% CO2 2.5%

MEAmine 49% MEAmine 0.076%

@25℃, 100kPa Nitrogen 0.0005%

@25℃, 90kPa

MS 18

207 kmol/h

Methane 0.07%

Ethane 0.0004%

Propane 0.05%

i-Butane 0.02%

n-Butane 0.03%

i-Pentane 0.03%

n-Pentane 0.03%

V-102

n-Hexane 0.06%

n-Heptane 0.31%

CO2 0.006%

MEAmine 99.4%

@25℃, 90kPa

9.

MS 22 MS 23




CO2 0.4% CO2 0.36%

MEAmine 0.0045% Nitrogen 0.45%

Nitrogen 0.45% @ -150℃, 1000kPa

@ -150℃, 1000kPa

MS 24

0.52 kmol/h

Methane 0.69%

Ethane 0.23%

Propane 0.007%

CO2 86%

MEAmine 13%

@-150℃, 1000kPa

10.

V-103

MS 25 MS 26



Ethane 1.8% Nitrogen 0.5%

CO2 0.36% @ -175℃, 1000kPa

Nitrogen 0.45%

@ -175℃, 1000kPa MS 27

40.5 kmol/h

Methane 19.8%

Ethane 66.3%

CO2 13.65%

Nitrogen 0.11%

@-175℃, 1000kPa

11.

MS 29 MS 31



Nitrogen 0.5% Ethane 0.20%

@ -140℃, 800kPa Nitrogen 0.46%

@−¿175.5℃, 689.5kPa

MS 37 MS 32


Methane 19.65% Ethane 79.8% Ethane 65.5%

V-104

T-102

CO2 14.56% CO2 19.9%

MEAmine 0.16% MEAmine 0.22%

Nitrogen 0.11%

@ -150℃, 1000kPa @-173.6℃, 689.5kPa

12.

MS 41

4500 kmol/h MS 43

H2O 100% 5970 kmol/h

@210℃, 1600kPa Methane 24.46%

Ethane 0.05% H2O 75.37%

MS 94 Nitrogen 0.11%

1470 kmol/h

Methane 99.34%

Ethane 0.20%

Nitrogen 0.46% @114.6℃, 1600kPa

13.

MS 44 MS 45

MIX-102



Ethane 0.05% CO 13%

H2O 75.37% H2O 47.69%

Nitrogen 0.11% Hydrogen 39.15%

@ 450℃, 1600kPa Nitrogen 0.09%

@ 690℃, 20kPa

MS 27 MS 46

496 kmol/h

Methane 99.4%

Ethane 0.6%

CO 0.007%

Hydreogen 0.0005

Nitrogen 0.0002%

@690℃,20kPa

14.

ERV-100

MS 45 MS 47


Methane 0.0075% Ethane 0.011%

CO 13% CO 3.85%

H2O 47.69% CO2 1.96%

Hydrogen 39.15% % H2O 18%

Nitrogen 0.09% Nitrogen 54%

@ 690℃, 20kPa Hydrogen 11.5%

Oxygen 10.5%

@ 700℃, 20kPa MS 46

MS 48

496 kmol/h 0 kmol/h

Methane 99.4%

Ethane 0.6%

CO 0.007%

Hydreogen 0.0005

Nitrogen 0.0002%

@690℃,20kPa

MS 119

17200 kmol/h

Oxygen 21%

Nitrogen 79% @544℃, 101.3kPa

15.

MS 47 MS 51

CRV-100


Ethane 0.011% CO 3.85%

CO 3.85% CO2 1.96%

CO2 1.96% H2O 18%

H2O 18% Hydrogen 11.5%

Hydrogen 11.5% Oxygen 10.5%

Oxygen 10.5% Nitrogen 54%

Nitrogen 54% @ 702℃, 20kPa

@ 700℃, 20kPa

MS 52

0 kmol/h

16.

MS 54 MS 51

25110 kmol/h 25110 kmol

CO 3.85% CO 0.04%

CO 3.85% CO2 5.8%

CO2 1.96% H2O 14.22%





@ 700℃, 20kPa

17.

MS 54 MS 60

CRV-102

ERV-101

25110 kmol/h 25110 kmol

CO 0.0008%

CO 3.85% CO2 5.84%

CO2 1.96% H2O 14.2%





@ 200℃, 20kPa

18.

MS 62 MS 63

25110 kmol/h 25110 kmol

CO 0.0008% CO 0.0008%

CO2 5.84% CO2 5.84%

H2O 14.2% H2O 14.2%

Hydrogen 15.4% Hydrogen 15.4%

Oxygen 10.4% Oxygen 10.4% Nitrogen 54%

@ 40℃, 20kPa Nitrogen 54%

@ 80℃, 20kPa

19.

MS 75 MS 78

ERV-101

V-105


CO 0.0008% CO 0.0009%

CO2 6% CO2 6.73%


Hydrogen 16% Oxygen 12%

Oxygen 11% Nitrogen 62.5%

Nitrogen 56% H2O 1%

@ 50℃, 1200kPa @ 50℃, 1200kPa

MS 80

3320 kmol/h

CO2 0.03%

H2O 99.88%

Hydrogen 0.003%

Oxygen 0.02%

Nitrogen 0.06%

@ 50℃, 1200kPa

20.

V-108

MS 78 MS 79


CO 0.0009% CO 0.0009%

CO2 6.73% CO2 6.73%


Hydrogen 17.8% Oxygen 12%

Oxygen 12% Nitrogen 62.5%

Nitrogen 62.5% H2O 1%

@ 50℃, 1200kPa @ 50℃, 1200kPa

MS 81

7254 kmol/h

CO 0.0009%

CO2 6.73%

H2O 1%

Hydrogen 17.8%

Oxygen 12%

Nitrogen 62.5%

@ 50℃, 1200kPa

21.

MS83 MS 84

TEE-100

21760 kmol/h 159900 kmol/h

CO 0.0009% CO 0.0003%

CO2 6.73% CO2 2.56%

H2O 1% H2O 0.15%

Hydrogen 17.8% Hydrogen 4%

Oxygen 12% Oxygen 0.15

Nitrogen 62.5% Methanol 0.06%

@85℃,1600 kPa Nitrogen 78.5%

@20.5℃,1600 kPa a

MS 109

138100 kmol/h

CO 0.0002%

CO2 1.9%

H2O 0.008%

Hydrogen 1.8%

Oxygen 15%

Nitrogen 81%

Methanol 0.07%

@10℃,7500 kPa

22.

MS 86 MS 89

159900 kmol/h 63960 kmol/h

CO 0.0003% CO 0.0003%

CO2 2.56% CO2 2.56%

H2O 0.15% H2O 0.15%

Hydrogen 4% Hydrogen 4%

Oxygen 0.15% Oxygen 0.15%

Methanol 0.06% Methanol 0.06%

Nitrogen 78.5% Nitrogen 78.5%

@ 220℃, 7500kPa @ 220℃, 7500kPa

MS 90

95930 kmol/h

CO 0.0003%

CO2 2.56%

H2O 0.15%

Hydrogen 4%

Oxygen 0.15%

Methanol 0.06%

Nitrogen 78.5%

@ 220℃, 7500kPa

23.

MS 90 MS 95

TEE-101


CO 0.0003% CO 0.0003%

CO2 2.56% CO2 1.4%

H2O 0.15% Hydrogen 0.34%

Hydrogen 4% Oxygen 0.15%

Oxygen 0.15% Nitrogen 82.5%


Nitrogen 56% H2O 0.03%

@ 50℃, 7500kPa @ 28℃, 7500kPa

MS 96

2398 kmol/h

CO2 0.07%

H2O 53.8%

Hydrogen 0.001%

Oxygen 0.035%

Methanol 45.96%

Nitrogen 0.06%

@ 28℃, 7500kPa

24.

MS 97 MS 85

ERV-104

63850 kmol/h 155000 kmol/h

CO2 2.56% CO 0.0002

H2O 0.01% CO2 1.88%

Hydrogen 4% H2O 0.025%

Oxygen 0.14% Hydrogen 1.85%

Methanol 0.03% Oxygen 15.17%

Nitrogen 78.6% Methanol 0.1%

@ 102.5℃, 7500kPa Nitrogen 80.96%

@ 58.88℃, 7500kPa

MS 96

91170 kmol/h

CO 0.003%

CO2 1.4%

H2O 0.03%

Hydrogen 0.34%

Oxygen 15.48%

Methanol 0.15%

Nitrogen 82.6%

@ 28℃, 7500kPa

25.

MS 91 MS 92


CO2 2.56% CO2 2.56%

H2O 0.15% Hydrogen 4%

Hydrogen 4% Oxygen 0.15%

Oxygen 0.15% Nitrogen 78.6%


Nitrogen 78.5% H2O 0.01%

@ 130℃, 7500kPa @ 10℃, 7500kPa

MS 93

104.3 kmol/h

CO2 0.18%

H2O 81.82%

Hydrogen 0.008%

Oxygen 0.05%

Methanol 17.83%

Nitrogen 0.11%

@ 10℃, 7500kPa

26.

ERV-103

MS 104 MS 105

155000 kmol/h 155000 kmol/h

CO 0.0002% CO 0.0002%

CO2 1.88% CO2 1.88%



Oxygen 15% Nitrogen 81%


Nitrogen 80.96% H2O 0.008%

@ 10℃, 7500kPa @ 10℃, 7500kPa

MS 106

74.46 kmol/h

CO 0.0002%

CO2 0.13%

H2O 35%

Hydrogen 0.01%

Oxygen 0.02%

Methanol 64.78%

Nitrogen 0.023%

@ 10℃, 7500kPa

27.

MS 104 MS 105

V-109

155000 kmol/h 15500 kmol/h

CO 0.0002% CO 0.0002%

CO2 1.88% CO2 1.88%



Oxygen 15% Nitrogen 81%


Nitrogen 81% H2O 0.008%

@ 10℃, 7500kPa @ 10℃, 7500kPa

MS 108

139500 kmol/h

CO 0.0002%

CO2 1.88%

H2O 0.008%

Hydrogen 1.85%

Oxygen 0.15%

Methanol 0.07%

Nitrogen 81%

@ 10℃, 7500kPa

28.

MS 93 MS 110

TEE-102

104.3 kmol/h 2577 kmol/h

CO2 0.18% CO2 0.07%

H2O 81.82% H2O 54.46%

Hydrogen 0.008% Hydrogen 0.002%

Oxygen 0.05% Oxygen 0.035


Nitrogen 0.11% Nitrogen 0.06%

@10℃,7500 kPa @26.81℃,1600 kPa

MS 96

2398 kmol/h

CO2 0.07%

H2O 53.87%

Hydrogen 0.001%

Oxygen 0.035%

Nitrogen 0.06%

Methanol 45.96%

@28℃,7500 kPa

MS 106

74.46 kmol/h

CO 0.0002%

CO2 0.13%

H2O 35%

Hydrogen 0.01%

Oxygen 0.02%

Methanol 64.78%

Nitrogen 0.023%

@ 10℃, 7500kPa

List of Major Equipments

Equipment Name No of equipment Equipment Designation Capacity

Separator 8 V100V102V103V104V105V106V107V108V109

1500 kmol/h420 kmol/h1124 kmol/h1124 kmol/h26700 kmol/h26450 kmol/h26330 kmol/h33720 kmol/h211400 kmol/h

Absorber 1 T100 1124 kmol/h gas5970 kmol/h liquid

Distillation Colum 4 T101

T102

T103

T104

420 kmol/h gas & 5600 kmol/h liquid 1100 kmol/h gas & 24.24 kmol/h liquid60.46 kmol/h gas & 1080 kmol/h liquid407.3 kmol/h gas & 607.76 kmol/h liquid

Reactor Equilibrium Reactor

5 ERV100ERV101ERV102ERV103ERV104

Conversion Reactor

3 CRV100CRV101CRV102

Heat Exchanger 18 E100E101E102E103E104E105E106E107E108E109E110E111E112E113

E114E115

4.207×107 kJ/h

-3.836×106 kJ/h-3.754×106 kJ/h-1.439×106 kJ/h-6.844×106 kJ/h4.349×105 kJ/h1.185×107 kJ/h5.276×107 kJ/h4.457×108 kJ/h1.664×107 kJ/h4.876×107 kJ/h1.881×107 kJ/h8.770×108 kJ/h4.086×108 kJ/h-2.342×108 kJ/h

E116E117

-2.804×108 kJ/h-3.185×108 kJ/h

Pump 2 P100P101

6000 kPa910 kPa

Compressor & Expander K100K101K102K103K104K105

-200 kPa30 kPa1570 kPa400 kPa5900 kPa880.8 kPa

List of Vendors

For Heat Exchangers

- Heat-Exchanger USA, McDonough, GA

- Industrial Heat Transfer,Inc., Coon Valley, WI

- PRE-HEAT,Inc.,Oostburg,WI

- Ambassador Heat Transfer Company, Cincinatti, OH

- JFD Tube & Coil Products,Inc.,Hamden

- Yula Corporation,Bronx,NY

For Pumps

- Afton Pumps

- AKAY Industries B.V.

- AlfaLaval

- Ruhrpumpen

- PumpEng

- PACO Pumps

- Magnatex

- Layne / VertiLine

For Compressor/Expander

- ATLAS COPCO, SWITZERLAND

- BORSIG GMBH, GERMANY

- DRESSER RAND, FRANCE

- ELLIOTT TURBOMACHINERY LTD. UK,

- INGERSOLL RAND CO. LTD., UK

- KKK, GERMANY

- LMF AG, AUSTRIA

- MANNESMANN DEMAG DELAVAL,GERMANY

For Distillation and Absorption Column

- Excel Plants & Equipment Pvt Ltd- Chem Dist Process Solutions- Rufouz Hitek Engineers Pvt. Ltd.- MaletaCD- Buflovak,LLC-Buffalo,NY- Fabco Products,Inc.-Hawkins,TX- Koch-Glitsch- Vessco

For Process Reactor

- Zhengzhou Keda Machinery and Instrument Equipment Co., Ltd- Atlas- RamTech- Parr Instrument Company- Ace Apparatebau construction & Engineering GmbH- MAN DWE GmbH- Michael Glatt Maschinenbau Gmbh -

http://www.kdinstrument.com/America/chemical-reactor-suppliers-us.html?gclid=CJbNnJab-cgCFasEwwodBDQCaA

http://www.hellotrade.com/michael-glatt-maschinenbau/

Design of Gas (Vapor)-Liquid Separators" and should be amended with the

following selection and design criteria:

a) Selection criteria

a.1) Orientation

In general, a vertical vessel is preferred for gas/liquid separation for the following

reasons:

- when the gas/liquid ratio is high;

- a smaller plan area is required (critical on offshore platforms);

- easier solids removal;

- liquid removal efficiency does not vary with liquid level;

- vessel volume is generally smaller.

However, a horizontal vessel should be chosen if:

- large volume of total fluid is available;

- large amount of dissolved gas is available;

- large liquid slugs have to be accommodated;

- there is restricted head room;

- a low downward liquid velocity is required (for degassing purposes, foam

breakdown or

in case of a difficult liquid/liquid separation).

a.2) Components

Following the gas/liquid flow path through the separator, the following parameters

should be identified:

- Feed inlet

This comprises the upstream piping, inlet nozzle, and the inlet devices (if any).

• The diameter of the inlet nozzle is a function of the feed flow rate and pressure.

• The criterion for the nozzle sizing is that the momentum of the feed shall not

exceed prescribed levels. The maximum allowable inlet momentum can be

increased by applying inlet devices.

• The function of the inlet device is to initiate the gas/liquid separation and to

distribute the gas flow evenly in the gas compartment of the vessel.

• Commonly used inlet devices are the half-open pipe and their specific proprietory

inlet devices designed for introducing gas/liquid mixtures into a vessel or column.

- Separator internals

• In knock-out vessels the diameter should be selected sufficiently large to keep the

gas velocity low at which the major portion ofthe droplets could be settled by

gravity.

• In all other types of gas/liquid separators, internals should be considered, for

selection the required duty, wire mesh, vane-pack (either horizontal or vertical

flow), multicyclones axial or reversed flow, filter candles, etc. should be studied.

- Gas and liquid outlets

After completion of the gas/liquid separation process the two phases will leave the

vessel via the gas and liquid outlet respectively.

- Gas handling capacity

The separator shall be large enough to handle the gas flow rate under the most

severe process conditions. The highest envisaged gas flow rate should be

determined by including a margin for surging, uncertainties in basic data. This

margin is typically between 15 and 50%, depending on the application.

- Selection strategy

1) Gas handling capacity:

- max. capacity (gas load factor);

- turndown ratio.

2) Liquid removal efficiency:

- overall;

- with respect to fine mist;

- with respect to the possible flooding above the maximal load factor (which will

affect the sharpness of the efficiency decline above the maximum capacity).

3) Liquid handling capacity:

- slugs;

- droplets.

4) Fouling tolerance:

- sand;

- sticky material.

5) Pressure drop:

The following selection strategy is suggested:

First define the mandatory requirements which the separator shall satisfy. Check,

whether there are limitations which will rule out horizontal or vertical vessels.

b) Design criteria

b.1) General

Unless explicitly stated otherwise, both the maximum gas and liquid flow rates

should contain a design margin or surge factor

b.2) Vertical and horizontal separators

Specific indication to process application, characteristics, recommended and non-

recommended use of various vertical/horizontal separators used in OGP production

plants are given hereunder for design consideration:

- Vertical Knock-Out Drum

Application:

- Bulk separation of gas and liquid.

Characteristics:

- unlimited turndown;

- high slug handling capacity;

- liquid removal efficiency typically 80-90% (ranging from low to high liquid

load).

- Warning: Liquid removal efficiency for mist is very poor

- very low pressure drop;

- insensitive to fouling.

Recommended use:

- vessels where internals have to be kept to a minimum (e.g., flare knock-out

drums);

- fouling service e.g., wax, sand, asphaltenes;

- foaming service.

Non-recommended use:

• where efficient demisting of gas is required.

Typical process applications:

• vent and flare stack knock-out drums;

• production separator;

• bulk separator (e.g., upstream of gas coolers);

• flash vessel.

- Horizontal Knock-Out Drum

Application:

• Bulk separation of gas and liquid.

Characteristics:

• can handle large liquid fractions;

• unlimited turndown;

• very high slug handling capacity;

• liquid removal efficiency typically 80-90% (ranging from low to high liquid

load).

- Warning: Liquid removal efficiency for mist is very poor

• insensitive to fouling;

• very low pressure drop.

Recommended use:

• vessels where internals have to be kept to a minimum and where there are height

limitations;

• slug catchers;

• fouling service, e.g., wax, sand, asphaltenes;

• for foaming or very viscous liquids.


• where efficient demisting of gas is required.


• vent and flare stack knock-out drums;

• production separator-low GOR;

• bulk separator;

• slug catcher.

- Vertical Wire Mesh Demister

Application:

• demisting of gas.

Characteristics:

• high turndown ratio;

• high slug handling capacity;

• liquid removal efficiency > 98%;

• sensitive to fouling;

• low pressure drop.

Recommended use:

• for demisting service with a moderate liquid load;

• where slug handling capacity may be required.


• fouling service (wax, asphaltenes, sand, hydrates);

• for viscous liquids where degassing requirement determines vessel diameter;

• for compressor suction scrubbers unlessprecautions are taken to prevent the

possibility of loose wire cuttings entering the compressor or plugging of the

demister mat increasing suction pressure drop.


• production/test separator:

- moderate GOR;

- non-fouling;

• inlet/outlet scrubbers for glycol contactors;

• inlet scrubbers for gas export pipelines;

• for small diameter and/or low pressure vessels, where extra costs of vane of SMS

internals cannot be justified.

- Horizontal Wire Mesh Demister

Application:

• demisting of gas where a high liquid handling capacity is required.

Characteristics:

• high turndown ratio;

• very high slug handling capacity;


• sensitive to fouling;

• low pressure drop.

Recommended use:

• typically for demisting service with a high liquid load and low GOR;

• applied where slug handling capacity may be required;

• for viscous liquids where liquid degassing requirement determines vessel

diameter;

• in situations where head room is restricted;

• for foaming liquids.

- Vertical Vane-Type Demister

Application:

• demisting of gas.

Characteristics:


• moderate turndown ratio;

• suitable for slightly fouling service (if without double-pocket vanes);

• robust design;

• sensitive to liquid slugs (in-line separator cannot handle slugs).

Recommended use:

• typically for demisting service;

• in-line separator to be used only with relatively low flow parameter (φfeed

< 0.01);

• two-stage separator to be used if φfeed 0.01; ≥

• attractive for slightly fouling service (if without double-pocket vanes);

• may be used where demister mats may become plugged, i.e., waxy crudes.


• heavy fouling service (heavy wax, asphaltenes, sand, hydrates);

• for viscous liquids where degassing requirement determines vessel diameter;

• the in-line vertical flow vane pack separator shall not be used where liquid

slugging may occur or where φfeed 0.01; ≥

• if pressure exceeds 100 bar (abs), due to the consequent sharp decline in liquid

removal efficiency.


• compressor suction scrubbers-where vane packs are preferred to demister mats

since their construction is more robust;

• demisting vessels with slightly fouling service.

- Horizontal Vane-Type Demister

Application:

• demisting of gas where a high liquid handling capacity is required.

Characteristics:


• moderate turndown ratio;

• suitable for slightly fouling service (if without double-pocket vanes);

• high slug handling capacity;

• robust design.


• heavy fouling service (heavy wax, asphaltenes, sand, hydrates);

• if pressure exceeds 100 bar (abs).


• production separator where GOR is low and the service is slightly fouling.

- Cyclone

Application:

• demisting of gas in fouling service.

Characteristics:


• insensitive to fouling;

• limited turndown ratio;

• high pressure drop.

Recommended use:

• typically for use in a fouling (e.g., coke-formation) environment and where a high

demisting efficiency is still required.


• if high pressure drop can not be tolerated.

Typical process application:

• in oil refineries: Thermal Gas-Oil Unit (TGU);

Visbreaker Unit (VBU);

• in chemical plants: Thermoplastic Rubber Plants.

- Vertical Multicyclone Separator

Application:

• demisting and dedusting of gas in slightly fouling service and high pressure.

Characteristics:


• suitable for slightly fouling service (e.g., low sand loading);

• high pressure drop;

• compact separator;

• sensitive to high liquid loading or slugs.

Recommended use:

• typically for use in a slightly fouling environment where the gas pressure is

higher

than 100 bar (abs) and a compact separator is required.


• low gas pressure;

•heavy fouling service (high sand loading will cause erosion);

• high liquid loading;

• slug;

• when high liquid removal efficiency is required.


• wellhead separators;

• primary scrubbers under slightly fouling service and when the liquid loading is

low;

• compressor suction scrubbers if sand is present in the feed.

- Filter Separator

Application:

• after-cleaning (liquid and solids) of already demisted gas when a very high liquid

removal efficiency is required.

Characteristics:


• very high pressure drop;

• sensitive to high liquid loading or slugs;

• sensitive to fouling by sticky material.

Recommended use:

• typically as a second-line gas/liquid separator to after-clean the gas stream exiting

from the first-line gas/liquid separator.

• use filter candles with the flow from OUT to IN where solids are present.

• use filter candles with the flow from IN to OUT where ultimate efficiency is

required and NO solids are present.


• heavy fouling (sticky material) service;

• high liquid loading;

• slugs.


• last demisting stage of natural gas prior to despatch for sale.

1. UDHE METHANOL TECHNOLOGY

2. JACOBS METHANOL TECHNOLOGY

3. LURGI METHANOL TECHNOLOGY

4. MITSUBISHI GAS CHEMICAL METHANOL TECHNOLOGY

5. HALDOR TOPSOE METHANOL TECHNOLOGY

6. TOYO PROCESS

7. LINDE PROCESS

Water treatment plant

Cooling tower

Steam generator/boiler

Electric power generator

Compressed air unit

Instrument air unit

Inert gas generation plant

Refrigeration plant

Flares and stack

Effluent treatment plant

Uninterrupted power supply

Facilities for support services

Laboratories

Maintenance shops

Garage and vehicular parking

Warehousing

Communication

Utilities for housing colony

No.

Area of application Organization Issuing Codes and Standard

1 Materials American Society for Testing and Materials(ASTM),American Society of Mechanical Engineers(ASME)

2 Pressure Vessels ASME3 Fired Boiler ASME4 Process Furnace API5 Welding Material ASME,American Welding Society(AWS)6 Shell and Tube Heat Exchanger Tubuler Exchanger Manufacturers

Association(TEMA),American Petroleum Institute(API)

7 Surface Condensers Heat Exchanger Institute(HEI)8 Cooling Tower Cooling Tower Institute(CTI)9 Storage Tank API, ANSI10 Rotating Equipment(Centrifugal

Compressor,Reciprocating Compressor,Blower,Turbine)

API

11 Refrigeration and Air Conditioning Equipment

American Society of Heating Refrigeration and Air Conditioning Engineering (ASHRAE)

12 Pressure piping ANSI, National Plumbing Code (NPC)13 Pressure Relieving System API14 Steel Structure ANSI15 Building and Concrete Structure American Concrete Institute16 Material Handling Facility CEMA,ANSI17 Electrical National Electric Code,API,ANSI18 Fire Protection and Safety National Fire Protection Association19 Safety Occupational Safety and Health

Administration20 Corrosion Protection National Association of Corrosion Engineers

TECHNICAL INFORMATION

Gas/Liquid Separators

Application Data Sheet

Name: ________________________________________________ Date: ________________________________________________________

Title: _________________________________________________________________________________________________________________

Company: ____________________________________________________________________________________________________________

Address: _____________________________________________________________________________________________________________

City: __________________________________________ State: _______ Zip: __________________________________________________

Phone: _________________________________ Fax: _______________________________________________________________________

E-Mail: _____________________________________________________________________________________

Equipment ID: H111

Product(s) of Interest

Cast ST and T Type Separators Fabricated L and T Type Separators Exhaust Heads

Cast LST Type Separators Receiver & Coalesce Type Separators Accessories

Air & Gas Drain Traps Air Vents

Application Parameters

Pipe Size: ___________ in ___________ mm

Flow Medium: Air Steam Natural Gas Other ___________________________________________________

Volumetric Flow: ___________ SCFM _______0.07____ MMSCFD ___________ NM3/hr

Weight Flow: _____________ lb/hr _____25390________ kg/hr

Average Molecular Weight: _____________________________________19.5____________________________________________

Minimum Operating Pressure: _______________ psig ___________ kg/cm2 ____70_____bar

Maximum Operating Temperature: ______________ °F _____25__________ °C

Flow Configuration Preference: __Vertical Flow____

Design Pressure of Vessel: _________________ psig ___________ kg/cm2 _____70____bar

Design Temperature of Vessel: _________________ °F ________25_______ °C

Maximum Entrained Liquid: ______________ lb/hr ____________ gpm _______88.865_____ kg/hr

End Connections Required: Threaded Flanged Socket Weld

125 lb 150 lb 300 lb Other ____________________________________________________________________

Materials of Construction: Cast Iron Carbon Steel 304L SS 316L SS

Other ____________________________________________________________________________________________________

project shihab

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