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
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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
Composition (Mass fraction)
CH3OH(Methanol) 0.968
CO2 0.031
b. Specification of fuel gas
conditions
Mass flow rate(ton/day) 6.9
Aqueous fraction 0
Composition (Mass fraction)
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
7450 kmol/h 7450 kmol/h
MEAmine 100% MEAmine 100%
@234.9℃, 7000kPa @45℃, 7000kPa
5.
E-101
MS 10 MS 11
7450 kmol/h 7450 kmol/h
MEAmine 100% MEAmine 100%
@263℃, 7000kPa @235℃, 7000kPa
MS 8 MS 9
7662 kmol/h 7662 kmol/h
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
7662 kmol/h 420 kmol/h
Methane 2.5% Methane 46%
Ethane 0.02% Ethane 0.35%
Propane 0.08% Propane 1.5%
i-Butane 0.02% i-Butane 0.44%
n-Butane 0.02% n-Butane 0.36%
i-Pentane 0.01% i-Pentane 0.22%
n-Pentane 0.0085% n-Pentane 0.17%
n-Hexane 0.008% n-Hexane 0.17%
n-Heptane 1.6% n-Heptane 0.45%
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
207 kmol/h 7450 kmol/h
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
420 kmol/h 212 kmol/h
Methane 46% Methane 90.68%
Ethane 0.35% Ethane 0.69%
Propane 1.5% Propane 3%
i-Butane 0.44% i-Butane 0.85%
n-Butane 0.36% n-Butane 0.68%
i-Pentane 0.22% i-Pentane 0.41%
n-Pentane 0.17% n-Pentane 0.31%
n-Hexane 0.17% n-Hexane 0.28%
n-Heptane 0.45% n-Heptane 0.59%
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
1500 kmol/h 1499 kmol/h
Methane 97.35% Methane 97.39%
Ethane 1.8% Ethane 1.8%
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
1499 kmol/h 1459 kmol/h
Methane 97.39% Methane 99.5%
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
1459 kmol/h 1470 kmol/h
Methane 99.5% Methane 99.34%
Nitrogen 0.5% Ethane 0.20%
@ -140℃, 800kPa Nitrogen 0.46%
@−¿175.5℃, 689.5kPa
MS 37 MS 32
41 kmol/h 7662 kmol/h
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
5970 kmol/h 7408 kmol/h
Methane 24.46% Methane 0.0075%
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
7408 kmol/h 25100 kmol/h
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
25100 kmol/h 25110 kmol/h
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%
H2O 18% Hydrogen 15.36%
Hydrogen 11.5% Oxygen 10.4%
Oxygen 10.5% Nitrogen 54%
Nitrogen 54% @ 220℃, 20kPa
@ 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%
H2O 18% Hydrogen 15.4%
Hydrogen 11.5% Oxygen 10.4%
Oxygen 10.5% Nitrogen 54%
Nitrogen 54% @ 80℃, 20kPa
@ 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
32360 kmol/h 29020 kmol/h
CO 0.0008% CO 0.0009%
CO2 6% CO2 6.73%
H2O 18% Hydrogen 17.8%
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
29020 kmol/h 21760 kmol/h
CO 0.0009% CO 0.0009%
CO2 6.73% CO2 6.73%
H2O 1% Hydrogen 17.8%
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
95930 kmol/h 91170 kmol/h
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%
Methanol 0.06% Methanol 0.15%
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
63960 kmol/h 63850 kmol/h
CO2 2.56% CO2 2.56%
H2O 0.15% Hydrogen 4%
Hydrogen 4% Oxygen 0.15%
Oxygen 0.15% Nitrogen 78.6%
Methanol 0.06% Methanol 0.03%
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%
H2O 0.025% Hydrogen 1.85%
Hydrogen 1.85% Oxygen 15%
Oxygen 15% Nitrogen 81%
Methanol 0.1% Methanol 0.07%
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%
H2O 0.008% Hydrogen 1.85%
Hydrogen 1.85% Oxygen 15%
Oxygen 15% Nitrogen 81%
Methanol 0.0% Methanol 0.07%
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
Methanol 17.83% Methanol 45.36%
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
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