CHEN3000 Process Plant Engineering
Semester 2 2016
Individual Assignment 1
Process Evaluations & P&IDs for Production of Syngas
“I
declare that this report is solely my own work with own effort and additional help from Dr.
Jibrail.”
No.
Miri/Perth ID
Student’s Name
Signature
1.
7e4b3541/ 17466835
Yee Min Juey
Yee
Date of Report Submission:
16/9/2016 (Friday)
Name of Lecturer:
Dr. Jibrail Kansedo
i
Table of Content
Title
Page number
1.0 Introduction
1
1.1 Problem statement
1
2.0 Process production methods of syngas
2
2.1 PSA-based steam methane reforming (SMR) process
2
2.1.1 Block flow diagram
4
2.1.2 Piping & Instrumentation Drawing
5
2.1.3 Process description
8
2.2 Coal gasification
10
2.2.1 Block flow diagram
10
2.2.2 Piping & Instrumentation Drawing
11
2.2.3 Process description
14
3.0 Discussion
16
3.1 Advantages and disadvantages of steam methane reforming
16
And integrated gasification combined cycle (IGCC)
3.2 Evaluation criteria for SMR and coal gasification process
17
3.2.1 Number of equipments
17
3.2.2 Cost
17
3.2.3 Efficiency
18
3.2.4 Environmental friendliness
19
4.0 Conclusion and Summary
19
5.0 Appendixes
20
5.1 Process flow diagram for steam methane reforming (SMR)
20
5.2 Process flow diagram for coal gasification (IGCC)
22
6.0 References
24
ii
List of Tables
Page number
Table 1: Table of composition of product hydrogen
3
Table 2: Table of comparison of advantages and disadvantages between
16
steam methane reforming and coal gasification
Table 3: Table of process comparison in terms of number of equipment
17
Table 4: Table of process comparison in terms of cost
17
Table 5: Table of process comparison in terms of efficiency
18
Table 6: Table of process comparison in terms of environmental friendliness
19
Table 7: Table of equipment list of PFD for steam methane reforming
20
Table 8: Stream table for the production of syngas from natural gas
21
Table 9: Table of equipment list of PFD for coal gasification
22
Table 10: Stream table for coal gasification using IGCC plants
23
List of Figures
Page number
Figure 1: Steam reforming before PSA development
2
Figure 2: Steam reforming with PSA system
2
Figure 3: Block flow diagram of modified PSA-based steam methane reforming
4
Figure 4: P&ID of modified PSA-based steam methane reforming
5
Figure 5: P&ID of major equipment, steam reformer
6
Figure 6: P&ID of major equipment, pressure swing absorption (PSA) unit
7
Figure 7: Block flow diagram of IGCC plants with carbon capture
10
Figure 8: P&ID of IGCC plants with carbon capture
11
iii
Page number
Figure 9: P&ID of major equipment, gasifier
12
Figure 10: P&ID of major equipment, Absorber
13
Figure 11: Process flow diagram of modified PSA-based steam methane reforming
20
Figure 12: Process flow diagram of IGCC plants with carbon capture
22
iv
1.0 Introduction
Syngas, an abbreviation for synthetic gas, is a fuel gas mixture consists of mostly
hydrogen, carbon monoxide and small amount of carbon dioxide. It can be produced
commercially by diverse methods such as steam reforming of natural gas, gasification of coal
and biomass as well as waste-to-energy gasification of waste residues.
Besides, syngas is a vital intermediate resource for production of hydrogen, ammonia,
methanol and hydrocarbon fuels. Since the formation of syngas is highly endothermic and
requires high temperatures to be reacted in reactor, its main application is electricity generation.
In addition, syngas is used as an intermediate in the industrial synthesis of ammonia, fertilizers,
fuels, solvent and synthetic materials. However, although syngas has 50% of the energy density
of natural gas, it cannot be burned directly as fuel source. Instead, it is burned in an integrated
gasification combined cycle (IGCC) where heat is captured for electricity (Biofuel, 2010).
For other applications, steam and hydrogen
hyd rogen from syngas are used for electricity
generation in refinery industry to extract crude oil, nitrogen and ammonia are used as fertilizers
and the production of plastics,
p lastics, carbon monoxide is used as industry feedstock and fuels, sulfur
for production of sulfuric acid as well as solids used as slag for roadbeds (Kris Walker, 2013).
1.1 Problem statement
The problem statement of this report is to complete
c omplete a preliminary evaluation information
by performing a detailed technical and economic feasibility study for two different processes of
syngas production. Then, a justification of the best process chosen will be made by evaluating
the advantages and disadvantages of the selected processes.
Thus, the two feedstock chosen for syngas production are coal and natural gas. The
processes involved are coal gasification and steam methane reforming (SMR) respectively.
Detailed description of both of these lab scale processes will be explained thoroughly supported
with BFD, PFD and P&ID as
a s well as assumptions so that the justification of the best process can
be done.
1
2.0 Process production methods of syngas
2.1 PSA-based steam methane reforming (SMR) process
There are several methods to produce syngas from hydrocarbon such as steam reforming
from natural gas (SMR), partial oxidation (PO) and autothermal reforming (ATR). In this report,
steam methane reforming is selected due to its cost-effective production as the ratio of hydrogen
to carbon monoxide is 3:1 and its high efficiency, about 86%, which is among the highest of all
the commercially available production methods.
Steam methane reforming (SMR) is a process whereby methane from natural gas is
heated with steam, usually with a catalyst, to produce a mixture of carbon monoxide and
hydrogen used in organic synthesis and as a fuel. Steam reforming reaction is also endothermic,
where heat must be supplied to the process for the reaction to proceed. In fact, SMR is the most
widely used process for the generation of hydrogen.
Besides, methane is chosen as feed as it is cheap, has higher performance with the reformer
and also widely available from sources in USA and Canada. It can be obtained from natural
resources such as wetlands and ocean as well as non-natural resources such as coal mines, waste
water and agriculture (Sajjad, 2016). The cost of production is also depending on natural gas prices
and is currently the least expensive among all hydrogen production techniques.
There are two types of steam methane reforming, which are conventional process and
PSA-based process. Conventional steam methane reforming has been
be en used widely for several
decades from 1920s until 1980s, where newer technology has been developed. For conventional
steam reforming for syngas production, the gas from the steam reformer will pass through
several conversion steps to minimize the carbon monoxide content. A CO2 removal system
removes the carbon dioxide. Any remaining carbon monoxide and carbon dioxide are reacted to
produce methane in a methanator. On the other hand, newer PSA-based steam methane
reforming implements only high temperature shift conversion and pressure swing absorption unit
(PSA) instead of methanation (UOP, 2016).
2
Figure 1: Steam reforming before PSA development (UOP, 2016)
Figure 2: Steam reforming with PSA system (UOP, 2016)
Table 1: Table of composition of product hydrogen (Basu, 2009)
Properties
Hydrogen
Conventional steam methane
Newer PSA-based steam methane
reforming
reforming
95-97
99-99.99
2-4
0.0001
0.00001-0.00005
0.00001-0.00005
0-2.0
0.1-1.0
purity, vol%
Methane,
vol%
CO + CO2,
vol %
Nitrogen,
vol%
From table above, it can be seen that newer PSA-based steam methane reformer produces
higher purity of hydrogen product with lesser impurities such as methane and carbon monoxide,
carbon dioxide and nitrogen. Thus,
Th us, newer PSA-based steam methane reforming process is
selected instead of conventional steam methane reforming process.
3
2.1.1 Block flow diagram
Figure 3: Block flow diagram of modified PSA-based steam methane reforming (Sukirgenk,
n.d)
4
2.1.2 Piping and Instrumentation Drawing
Figure 4: P&ID of modified PSA-based steam methane reforming
5
Figure 5: P&ID of major equipment, steam reformer
6
Figure 6: P&ID of major equipment, pressure swing absorption (PSA) unit
The control parameters in PSA unit are temperature, pressure and level, while the control
parameter in steam reformer are temperature, pressure
pressure and flow rate. To monitor and control the
temperature in PSA and steam reformer, the following sequence of control instrumentation can be
installed from temperature element or emitter (TE), temperature transducer or transmitter (TT),
temperature recorder controller (TRC), temperature alarm low and high (TAL & TAH), temperature
actuator or yield (TY) to temperature control valve (TCV). The control is repeated by varying the
control parameters
parameters such as pressure and flow rate, with similar technique applied above.
7
2.1.3 Process description of PSA-based steam methane reforming
There are mainly five steps to produce syngas, which contains high purity of hydrogen
product, such as natural gas desulfurization, catalytic steam reforming, water shift
shift gas reactions,
CO2 removal and pressure swing adsorption. There are
a re some assumptions made in the process,
such as the increment of pressure through the pump is twice of initial pressure, no pressure drop
throughout the system and the molar flow in is equal to molar flow out.
For the first step, methane is passed through a desulfurizer to remove sulfur impurities by
stream 101. It is to prevent poisoning of the nickel catalyst in the steam reformer.
Desulfurization can be accomplished by using either activated carbon or zinc oxide. Since a
small amount of hydrogen is used from the product stream, the product, H 2S gas, is then
removed in a ZnO bed by stream 103. Zinc oxide bed offers several advantages over the
activated carbon bed as no air emission is created by the zinc oxide bed, thus the high molecular
weight of hydrocarbons are not removed. Therefore, the heating value of the natural gas is
maintained (Chemtubee, 2011).
For catalytic steam reforming, natural gas leaving the desulfurization tank is mixed with
process steam from stream 105 and preheated to 360 OC. A mixer, M-101, is used to pass the
mixture of steam and gas into the steam reformer by stream 106, which is filled with a nickelbased reforming catalyst at a pressure of 1.0 MPa. The equation of steam-methane reforming
reaction is given as below.
CH4 + H2O → CO + 3 H2. Endothermic reaction. (Equation 1)
It is assumed that approximately 51 percent of the methane is converted to hydrogen and
CO2, while small amount of methane is converted
c onverted to CO. Sufficient air from off-gas is added so
that a final synthesis gas with hydrogen-to-nitrogen mole ratio of 3 to 1 can be produced. The gas
leaving reformer is then cooled to 220°C by passing through condenser in stream 108
108.. Tail gas is
removed from the system as purge to prevent
p revent pressure build up in the system, while most of the
gas is passed to water shift gas reactors by stream 110.
In water gas shift reaction, the carbon monoxide (CO) produced is reacted with steam
over a catalyst to form hydrogen and carbon dioxide (CO2) at an elevated pressure of 5.0 MPa by
using centrifugal pump, C-101. The equation of the water-gas shift reaction is stated as below.
8
CO + H2O → CO2 + H2. Exothermic reaction. (Equation 2)
o
This process occurs in two stages, consisting of a high temperature shift (HTS) at 320 C
in stream 110 and a low temperature shift (LTS) at 220 oC in stream 112. Notice that a
modification is done in the process. A PSA-based
PSA-ba sed reformer can be designed to work on only LTS
stages, but it’s been observed that incorporating both
bo th HTS and LTS stages improves efficiency
and therefore increases the amount of hydrogen produced. The combined WGS reactions can
thus be summarized as below (Wikiversity, 2016).
CH4 + 2H2O → CO2 + 4H2. Exothermic reaction. (Equation 3)
Note the water-shift reaction is exothermic, which results in a temperature increase across
the reactors as water reacts with CO to form CO2 and more H2. Water shift gas equilibrium is not
n ot
affected by pressure, since there is no volume change. Reduced temperatures by using condenser,
E-102 favours the conversion of CO to H 2, as might be expected by its exothermic nature. A
variety of catalysts are available for the service.
Next, the gas mixture is sent to stripper for the removal
removal of carbon dioxide by stream 114.
The stripper uses a steam reboiler to regenerate the solvent, stripping out the absorbed carbon
dioxide. In addition, improvement of the CO2 removal can be done by implementing
monoethanolamine, C2H4NH2OH scrubbing and hot potassium scrubbing to speed up the
removal process (Chemtubee, 2011).
Finally, the small amount residual in the syngas, such as CO2, CO and unconverted
methane is passed to Pressure Swing Adsorption unit (PSA) by stream 116 for further removal
process. PSA unit consists of two fixed bed absorbers, V-107 and V-108, which operate in a
high-pressure to low-pressure cycle to adsorb and then release contaminants. The impurities
desorb from the bed upon swinging the absorber from the feed to the off-gas by using adsorptive
materials such as zeolites and activated carbon. The adsorbent does not adsorb the hydrogen.
Besides, all the valve openings and closings are all controlled by the central processing unit (Arie,
2010).
9
Stream 119 is then split into two parts, where the 99.99% pure hydrogen product to
storage vessel, V-109 via stream 120 and some of the hydrogen product slipstream is recycle
back to desulfurizer, V-101 as a medium for desulfurization process via stream 121.
2.2 Coal gasification
Gasification is a key fundamental conversion technology which converts any carboncontaining material, such as coal into synthesis gas. It has been around for more than 200 years.
The chemical industry and the refinery industry applied gasification in the 1960s and 1980s,
respectively, for feedstock preparation. For instant, gasification was used extensively
e xtensively during
World War II to convert coal into transportation fuels via the Fischer-Tropsch process and for
the production of ammonia/urea fertilizer. The fast development of gasification is due to the
continuing high price of natural gas and highway transportation fuels (Ronald, 2010).
Nowadays, most of the industries implements Integrated Gasification
Gasification Combined Cycle
(IGCC) technology in converting coal and other carbon based fuels in syngas by using a high
pressure gasifier. It can remove impurities such as sulfur,
sulfur, tar and particulate in coal so that the
purity of the hydrogen in the syngas can be boosted.
2.2.1 Block flow diagram
10
Figure 7: Block flow diagram of IGCC plants with carbon capture (Ronald, 2010)
2.2.2 Piping & Intrumentation Drawing
11
Figure 8: P&ID of IGCC plants with carbon capture
12
Figure 9: P&ID of major equipment, gasifier
13
Figure 10: P&ID of major equipment, Absorber
The control parameters in gasifier are temperature, pressure and flow, while the control
parameter in the absorber are temperature, pressure and level. To monitor and control the
temperature in gasifier and absorber, the following sequence of control instrumentation can be
installed from temperature element or emitter (TE), temperature transducer or transmitter (TT),
temperature recorder controller (TRC), temperature alarm low and high (TAL & TAH),
temperature actuator (TY) to temperature control valve (TCV) and repeated by control
parameters such as pressure and flow rate, with similar
similar to technique applied on PSA unit.
Apart from temperature and pressure, there is another parameter to be controlled in absorber,
which is the level of liquid in the reactor. The level of liquid in the CSTR can be monitored and
controlled using these series of control instrumentation; level element or emitter (LE) – installed
directly to the CSTR body, level transmitter or transducer (LT), level recorder controller (LRC), level
alarm low and high (LAL & LAH), level actuator or yield (LY) and level control valve (LCV) –
connected to the pipe for syngas outlet.
14
2.2.3 Process description of coal gasification by IGCC plant
There are some assumptions made before the start of the coal gasification process, such
as the feed and air enter the system at ambient temperature, the increment of pressure through the
pump is twice the initial pressure, pressure drop throughout
throughout the system is negligible, friction in
pipelines and fittings is ignored and the molar flow in is equal to molar flow
flow out.
In the initial step of coal gasification process by integrated gasification combined cycle
(IGCC) technology, coal is first slurried with water and fed with pure oxygen and steam to the
gasifier via stream 103. Gasifier is the heart of a gasification-based
g asification-based system. It converts
hydrocarbon feedstock into gaseous components by applying heat under pressure in the presence
of steam.
The difference between a gasifier and combustor is that the amount of air or oxygen
available inside the gasifier is carefully controlled so that the coal is partially combusted in this
stage to maintain at a temperature of approximately
ap proximately 1,371 °C (NETL, 2016). Majority of the coal
reacts at this temperature with steam to produce the raw syngas via stream 105. Ash in the coal
melts and flows out of the bottom of the gasifier vessel as slag solids via stream 104.
Then, the raw syngas exits at temperature of 1038 °C and is passed through cyclones via
stream 105. Cyclone is the first syngas cleanup process applied to the remove up to 90% of
particulate matter in the raw gas (Awais, 2014). Next, the raw syngas is transferred
transferred to tar
scrubber to remove tar by thermal cracking as heater provides the sufficient heat. The raw syngas
is further cleaned by passing through the desulfurizer to remove the sulfur in the raw gas v
via
ia
stream 110. The sulfur can be further used to process sulfuric acid.
After that, clean syngas passes through a shift reactor, V-105 and an absorption tower, V106 to remove the carbon
ca rbon in the form of carbon dioxide via stream 114. The shift reactor
converts the CO in the syngas by reacting it with water to form H2 and CO2. Finally, part of
clean syngas with about 90% purity
pu rity of hydrogen exits the system via stream 115 and to be stored
in storage tank, V-108.
15
Then, the integrated gasification combined cycle system starts from stream 116 to stream
121. The plant is called integrated because the syngas produced in the gasification section is used
as fuel for the gas turbine, V-109 in the combined cycle, and steam produced by the syngas
coolers in the gasification section is used by the steam turbine in the combined ccycle.
ycle. The
combination of gas turbine and steam turbine is known as combined cycle.
Furthermore, part of the syngas produced is used as fuel in a gas turbine produces
electrical power. Thus, the energy is then used in a Heat Recovery Steam Generator (HRSG) to
make steam for the steam turbine cycle, V-111, via stream 121 and to produce additional
electrical power for external use.
In overall, the process is reversible. The coal gasification follows a combination of
following reaction as below (J. S. Brar et al, 2012).
2C + O2 <=> 2CO
Partial oxidation
(Equation 4)
C + O2 <=> CO2
Complete oxidation
(Equation 5)
CO + H2O <=> CO + 3H2
Shift reaction
(Equation 6)
C+ 2H2O <=> CO + H 2
Water gas reaction
(Equation 7)
Nowadays, commercially available gasification-based systems can operate at around 40%
efficiencies, while IGCC systems able to achieve efficiencies of 60% with the deployment of
advanced high pressure solid oxide fuel cells (U.S Department of Energy, n.d).
16
3.0 Discussion
3.1 Advantages and disadvantages of steam methane reforming and coal gasification
Table 2: Table of comparison between steam methane reforming and coal gasification
Steam methane reforming
Integrated gasification
combined cycle of coal
Advantages
- High efficiency, about 86% and cost
effective
- Does not require the mixing of air
a ir in the
reaction mixture, thus produces higher H 2
concentration in syngas (Robin and
Donald, 2002)
- Used at large scale in industrial syngas
production
- Relative stable during transition
operation.
- Natural gas, methane is abundant and
burns cleaner without any ash or smoke.
Disadvantages - High capital cost due to high system
complexity
- Prohibited for small to medium size
applications as the technology does not
scale down well
- High energy consumption as it require
an external heat source due to the
endothermic reactions that occur
- Potential high level of carbonaceous
material formation.
- Low start-up as it requires external
igniter to start up although the catalyst bed
can be used for catalyst combustion.
(Robin and Donald, 2002)
- Natural gas, methane is non-renewable
and will be depleted over time.
- Higher production efficiency,
about 60% than conventional
coal plant, about 45%
- 50% lower CO2 emission,
compared to conventional coal
plants
- The syngas produced is
virtually free of fuel-bound
nitrogen (U.S Department of
Energy)
- CO2 can be captured and,
stored in solid or liquid form
through sequestration.
- Energy efficient as waste heat
can be utilized to generate
electricity.
- High capital cost compared to
conventional coal plant.
- High emission of carbon
dioxide compared to natural gas
and leads to global warming.
- Extremely high inlet
temperature and pressure
required to be supplied to the
gasifier.
- Requires many stages of
syngas cleanup to remove bulk
particulates, tar, sulfur, slag and
CO2
- Health problems and possible
fatalities of mining worker due
to dangerous in extracting coal.
- Burning dirty coal can create
significant pollution problems,
such
as acid rain and air
pollution.
17
3.2 Evaluation criteria for steam methane reforming and coal gasification
3.2.1 Number of equipments
Table 3: Table of process comparison in terms of number of equipments
PSA-based steam methane reforming
Coal gasification
15
15
Explanation
In the steam methane reforming process, the unit
u nit operations include mixing, desulfurizing,
purification, steam reforming, shift converting, stripping and adsorption.
In the coal gasification by IGCC, the unit operations involve gasifying, purifying, filtration,
thermal cracking, desulfurizing, combustion, and absorption.
Both of the processes utilizes 15 equipment, including utilities such as heat exchanger,
pumps and compressors.
However, in the integrated gasification combined cycle, clean syngas can be produced by
using only 10 equipment, excluding combustor, gas turbine, steam turbine and heat recovery
steam generator, which contributes to electricity generation. Thus, it requires less equipment
for coal gasification by IGCC than PSA-based steam methane reforming.
3.2.2 Cost
Table 4: Table of process comparison in terms of cost
PSA-based steam methane
reforming
Coal gasification
Raw material cost
Methane: $2.71/million BTU
(EIA, 2016)
Steam: $0.016/kg
Coal: $19.43/million BTU (EIA,
2016)
Steam:$0.016/kg
Electricity cost
$55/MWh (EIA, 2016)
$55/MWh (EIA, 2016)
Estimated total cost for
producing 8600 tonnes of H2 per
year:
$23 million per year
(wikiversity, n.d)
Estimated total cost for
producing 8600 tonnes of H2 per
year:
$50 million per year
Equipment cost
Start-up cost
Operating cost
Maintenance cost
Transportation cost
18
Explanation
The research above is done based on the current raw material prices in U.S.A. It can be seen
that the raw material used in the IGCC, which is coal costs at a higher price (about 7 times)
than natural gas, methane. This might be due to the high demand and low supply of coal.
Besides, coal mining in deep underground involves high risk and requires lots of manpower.
Thus, it pushes the price of coal to be higher than natural gas.
In overall, the other reason that the total cost of coal gasification seems to be higher than
steam methane reforming is because the inefficiency in transportation of coal and also
expensive installation cost of the specialized cleanup vessels. Besides, the maintenance cost
is also expected to be higher in coal gasification as it requires regular cleaning of the tanks in
filtering particulate matter, slag and sulfur.
3.2.3 Efficiency
Table 5: Table of process comparison in terms of efficiency
PSA-based steam methane reforming
Coal gasification
86% (High)
60% (Moderate)
Explanation
It is found that the efficiency of PSA-based
PSA -based steam methane reforming in the production of
syngas is higher than coal gasification. This is because less methane is required to generate
high 99.99% purity of hydrogen in syngas, resulting in reduction of emission of greenhouse
greenho use
gases. Besides, it is also energy- efficient as it adopts lower temperature ( < 500 OC ) and
pressure (5 MPa) in the system, compared to coal gasification ( > 1000 OC , 10MPa)
On the other hand, coal gasification has a moderate energy efficiency as the waste heat can be
recycled and utilized to generate electricity. Besides, since combined cycle is used in IGCC to
generate efficiency, the fuel efficiency can potentially to be boosted to 50 percent or more.
19
3.2.4 Environmental friendliness
Table 6: Table of process comparison in terms of environmental friendliness
PSA-based steam methane reforming
Coal gasification
- Lower emission of carbon dioxide
- Dangerous when leakage occurs in the water
supply
- Thermal pollution
Explanation
- Higher emission of carbon dioxide, global
warming
- Acid rain, health problems, water pollution
- Thermal pollution
PSA-based steam methane reforming is found to emit 50% less carbon dioxide than coal during
combustion, causing less global warming (Sarah, 2014). However,
Ho wever, there is also a conflict that
natural gas is predominantly composed of methane, which is a more potent greenhouse gas
than carbon dioxide. Besides, leakage of natural gas can be have serious consequences as
methane is more toxic and flammable than carbon dioxide.
On the other hand, since coal naturally contains sulfur, it produce sulfur oxides when burned in
air, which contributes to acid rain. In addition,
a ddition, coal gasification emits particulate matter, which
causes an increase in respiratory problem such as asthma.
Finally, the use of water as a coolant by coal gasification and steam reforming causes thermal
pollution, in which the water quality is degraded and water temperature is changed. The change
in temperature in water affects the ecosystem in marine life when discharged into lakes by
decreasing the oxygen supply (Sourcewatch, 2015).
4.0 Conclusion and Summary
Based on the evaluation criteria as well as the advantages and disadvantages of PSAbased steam methane reforming and coal gasification, PSA-based steam methane reforming is
chosen as the best process as it is the most environmental-friendly, energy efficient and costeffective process in producing high purity of H2 in syngas. In conclusion, the preliminary
investigation and research on both the technologies has been successfully done with
comprehensive and detailed analysis.
20
5.0 Appendixes
5.1 PFD for steam methane reforming
Figure 11: Process flow diagram of modified PSA-based steam methane reforming (Donald,
Jason, Michael, Stephanie 2006)
Table 7: Table of equipment list of PFD for steam methane reforming
21
Table 8: Stream table for the production of syngas from natural gas (Donald et al, 2006)
Stream
number
101
102
103
104
105
106
107
108
109
110
Temperature
(OC)
30
30
30
30
210
360
360
320
320
320
Pressure
(MPa)
1.0
1.0
1.0
1.0
1.0
5.0
5.0
5.0
5.0
5.0
Molar flow
rate(kmol/h)
800
800
800
800
2200
3000
3000
3000
2500
2500
Hydrogen
0
0
0
0
0
0.08
0.51
0.51
0.51
0.51
Methane
1.0
1.0
1.0
1.0
0.0
1.0
0.23
0.23
0.23
0.23
Carbon
monoxide
0
0
0
0
0
0
0.01
0.01
0.01
0.01
Carbon
dioxide
0
0
0
0
0
0
0
0
0
0
Water
0
0
0
0
1.0
0.68
0.68
0.68
0.68
0.68
Details
NG
feed
Sulf
ur
NG
feed
NG
feed
Water
Gas
mixture
Gas
mixture
Gas
mixture
Gas
mixture
Gas
mixture
Mole fraction
Stream
number
Temperatur
e (OC)
Pressure
(MPa)
Molar flow
rate(kmol/h
)
Mole
fraction
Hydrogen
111
112
113
114
115
116
117
118
119
120
121
300
220
220
200
200
200
200
200
200
200
200
5.0
5.0
5.0
5.0
5.0
10.0
10.0
10.0
10.0
10.0
10.0
2000
2000
2000
2000
1800
3000
1500
1500
3000
1500
1500
0.68
0.68
0.68
0.68
0.75
0.75
0.75
0.75
0.75
0.99
0.99
Methane
0.01
0.01
0.01
0.01
0.01
0.01
0
0
0
0
0
Carbon
monoxide
Carbon
dioxide
Water
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.07
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0.01
0
0
0.23
0.23
0.23
0.23
0.10
0.10
0
0
0
0
0
Details
Gas
mixtur
Gas
mixture
Gas
mixtur
Gas
mixtur
PSA
feed
PSA
feed
Syn
gas
Syn
gas
Syn
gas
Syn
gas
Syn
gas
e
e
e
22
5.2 PFD for coal gasification
Figure 12: Process flow diagram of IGCC plants with carbon capture (Ronald, 2010)
Table 9: Table of equipment list of PFD for coal gasification
23
Table 10: Stream table for coal gasification using IGCC plants
Stream
number
Temperature
(OC)
Pressure
(MPa)
Molar flow
rate(kmol/h)
Mole. fr
Hydrogen
100
101
102
103
104
105
106
107
108
109
110
30
1371
30
1371
1371
1371
1371
2500
2500
1
1500
500
1500
5
10
5
10
10
10
10
10
10
10
10
1000
1000
1000
1000
200
1780
1760
1760
1600
1600
1400
0
0
0
0
0
0.88
0.88
0.88
0.88
0.88
0
Coal
1.0
1.0
0
0
0
0.02
0.02
0
0
0
0
Air
0
0
1.0
1.0
0
0
0
0
0
0
0
Carbon
monoxide
Solid
0
0
0
0
0
0.01
0.01
0.01
0.01
0.01
0
0
0
0
0
1.0
0
0
0
0
0
0
Sulfur
0
0
0
0
0
0
0
0.01
0.01
0.01
1.0
Carbon
dioxide
Water
0
0
0
0
0
0.03
0.03
0.08
0.08
0.08
0
0
0
1.0
0
0
0.02
0.02
0.02
0.02
0.02
0
Details
Coal
feed
Coal
feed
Air,
Steam
Air,
Steam
Solid
Raw
syngas
Raw
syngas
Raw
syngas
Raw
syngas
Raw
syngas
Sulfur
Stream
number
Temperature
(OC)
Pressure
(MPa)
Molar flow
111
112
113
114
115
116
117
118
119
120
121
1500
1000
1000
1000
1000
1000
30
1000
1000
1000
1000
10
10
10
10
10
10
10
10
10
10
10
1400
1300
1200
100
1100
100
2000
2100
2000
500
1500
rate(kmol/h)
Mole. fr
Hydrogen
0.90
0.90
0.90
0
0.99
0.99
0
0.99
0.99
0.99
0
Coal
0
0
0
0
0
0
0
0
0
0
0
Air
0
0
0
0
0
0
1.0
0
0
0
0
Carbon
monoxide
Carbon
dioxide
Water
0.01
0.01
0.01
0
0.01
0.01
0
0.01
0.01
0.01
0
0.08
0.08
0.08
1.0
0
0
0
0
0
0
0
0.01
0.01
0.01
0
0
0
0
0
0
0
1.0
Details
Clean
Clean
Clean
CO
Clean
Clean
Air
Clean
Clean
Clean
Steam
syngas
syngas
syngas
syngas
syngas
syngas
syngas
syngas
24
6.0 References
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http://www.azocleantech.com/article.aspx?ArticleID=377
Biofuel, 2010. Syngas. Retrieved from:
http://biofuel.org.uk/syngas.html
Sajjad, 2016. Episode 3: Production of Synthesis Gas by Steam Methane Reforming. Retrieved
from: http://www.slideshare.net/sajjad_al-amery/episode-3-production-of-synthesis-gas-bysteam-methane-reforming?qid=ab70d42f-8a7c-4ffc-a85c219c430fa366&v=&b=&from_search=4
Anupam Basu, 2009. Hydrogen production in refinery. Retrieved from:
http://www.slideshare.net/mech.anupam/hydrogen-production-in-refinery?qid=04fe0d69-30e64358-9eb6-e8be165cb657&v=&b=&from_search=6
Arie Gumilar, 2010. Hydrogen Production By Steam Reforming. Retrieved from:
http://chemeng-processing.blogspot.my/2010/05/hydrogen-production-by-steam-reforming.html
Sukirgenk, n.d. Natural gas reformer
reformer hydrogen. Accessed 9 September. Retrieved from:
http://sukirgenk.dvrlists.com/natural-gas-reformer-hydrogen.html
Donald Scott, Jason Hixson, Michael Hickey, Stephanie Wilson, 2006.
Plant Section 100-Syngas Production. Retrieved from:
http://chem.engr.utc.edu/ench430/2006/PPE-Production-Report-Final.htm
UOP, April 2016. UOP Polybed™ Pressure Swing Adsorption (PSA) Systems. Retrieved from:
https://www.uop.com/?document=psa-systems-for-hydrogen-production-by-steamreforming&download=1
Chemtubee, 2011. Ammonia process. Retrieved from:
http://chemtubee.blogspot.my/2011_05_01_archive.html
Wikiversity, 2016. Design for the Environment/Hydrogen Production. Retrieved from:
https://en.wikiversity.org/wiki/Design_for_the_Environment/Hydrogen_Production
Ronald W. Breault, 2010. Retrieved from:
Gasification Processes Old and New: A Basic Review of the Major Technologies. Energies
2010, 3, 216-240; doi:10.3390/en3020216
25
Awais Chaudhary, 2014. Production of Syngas from Biomass. Retrieved from:
http://www.slideshare.net/Awaischaudhary/production-of-syngas-from-biomass
NETL, 2016. WABASH RIVER COAL GASIFICATION REPOWERING PROJECT.
Retrieved from: HTTPS://WWW.NETL.DOE.GOV/RESEARCH/COAL/ENER
HTTPS://WWW.NETL.DOE.GOV/RESEARCH/COAL/ENERGYGYSYSTEMS/GASIFICATION/GASIFIPEDIA/WABASH
U.S Department of Energy, n.d. How Coal Gasification Power Plants Work. Accessed 12
September. Retrieved from: http://energy.gov/fe/how-coal-gasification-power-plants-work
J. S. Brar, K. Singh, J. Wang, and S. Kumar, 2012. Cogasification of Coal and
an d Biomass: A
Review. International Journal of Forestry Research
Volume 2012 (2012), Article ID 363058, 10 pages
http://dx.doi.org/10.1155/2012/363058
Robin Wang and Donald Rohr, 2002. NATURAL GAS PROCESSING TECHNOLOGIES FOR
LARGE SCALE SOLID OXIDE FUEL CELLS. Retrieved
Re trieved from:
https://web.anl.gov/PCS/acsfuel/preprint%20archive/Files/47_2_Boston_10-02_0292.pdf
EIA, U.S Energy Information Administration, 2016. Daily Prices. Retrieved from:
https://www.eia.gov/todayinenergy/prices.cfm
Sarah Zielinski, 2014. Natural Gas Really Is Better Than
Tha n Coal. Retrieved from:
http://www.smithsonianmag.com/science-nature/natural-gas-really-better-coal-180949739/?noist
Sourcewatch, 2015. Environmental impacts of coal. Retrieved from:
http://www.sourcewatch.org/index.php/Environmental_impacts_of_coal#cite_note-thermal-27
26