Tsinghua BP clean energy Research and Education centre

1. 1

2. Executive Summary
During the past two years, mainly two parts of work have been conducted under CEFTF
framework for polygeneration system study. The first part is polygeneration system study itself,
that is, to develop a versatile computer modelling platform dealing with the combination
modelling of power generation and chemical production and to study the polygeneration system
performance using the platform. The second part is to develop guidelines for safe and effective
implementation of carbon capture and storage (CCS) for China. This part is an extension or
continuation of the first part. As CCS has gained more and more attention due to the international
concern of global climate change, to treat poly-generation system as a enabling technology for
CCS may become a compelling reason for the commercialization for polygeneration. With BP’s
support through director funding to build up a strong and durable research team, the Tsinghua-BP
clean energy research and education center has conducted extensive research on this field and
regards the CCS related work as a part of the work under CEFTF framework.
The first part of the CEFTF project has been accomplished successfully. A library or “model
shelf” based on Aspen plus has been established with a full-set of sub-models for polygeneration
system modelling. To make use of the powerful tools provided by GT-pro in calculating the gas
turbine and steam turbine combined cycle, an interface connecting Aspen plus and GT-pro
together has been developed. Using these sub-models and the Aspen plus GT-pro connector, a
modeling platform has been developed successfully, making it convenient to establish an
integrated model for a new designed polygeneration system and study the system performance.
The construction of CCS guidelines for China is a very comprehensive project and requires
multi-disciplinary knowledge. Currently, a draft report, ‘Guidelines for Safe and Effective Carbon
Capture and Storage’, has been finished. Besides, several related projects have been conducted or
started by the Tsinghua-BP center to complement for the CCS guidelines study. A Tsinghua
oxygen staged entrained-flow gasifier model has been established, which is able to serve as a
strong basis for future CCS power plant system performance study and operator training. A lab has
been built up to study one of the key issues for CCS, metal corrosion in CO2 pipeline
transportation process., The objective of this work is to provide the basis to set up a standard for
CO2 purity and potentially to significantly decrease energy and economical cost in CO2 capture,
transportation and storage. Laser induced breakdown spectroscopy (LIBS) system has also been
established for online coal composition measurement to improve gasification/combustion
efficiency to partly compensate the energy loss due to CO2 capture. An initial CO2 source and sink
matching study has also been finished, providing a basic framework for China to build up its CO2
transport pipeline network. The techno-economic assessment of CO2 capture systems has been
accomplished under the support of EU-China projects (COACH and NZEC), providing the
priority of CO2 capture system development in China. All of this work will be systematically
incorporated into the China CCS guidelines project.
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3. TABLE OF CONTENT
EXECUTIVE SUMMARY...........................................................................................................................2
PART 1: POLYGENERATION SYSTEMS STUDY............................................................................5
1.1.MODEL SHELF OF UNIT MODELS FOR POLYGENERATION SYSTEM....................................................5
1.1.1. Gasifier modeling....................................................................................................................5
1.1.2. Air separation unit...................................................................................................................6
1.1.3. Gas purification units..............................................................................................................6
1.1.4. Water gas shift reactor............................................................................................................7
1.1.5. Methanol synthesis and distillation.........................................................................................8
1.2.ADVANCED SYSTEM SIMULATION PLATFORM WITH INTEGRATION OF ASPEN PLUS & GTPRO.......10
1.2.1. Purpose..................................................................................................................................10
1.2.2. Software Integration Framework..........................................................................................11
1.2.3. Example.................................................................................................................................12
1.3.GAS TURBINE PERFORMANCE WITH SYNGAS FUEL.........................................................................15
1.3.1. Gas turbine modelling...........................................................................................................15
1.3.2. Specification of boundary conditions ...................................................................................17
1.3.3. Results and discussion ..........................................................................................................17
1.3.4. Conclusion.............................................................................................................................21
1.4.AN INTEGRATED CATALYTIC CO2 / CH4 REFORMING APPROACH TO DUAL FUEL MEOH AND
POWER POLYGENERATION ....................................................................................................................23
1.4.1. Introduction...........................................................................................................................23
1.4.2. System scheme ......................................................................................................................23
1.4.3. Modeling of core equipment: autothermal reforming...........................................................24
1.4.4. Simulation results and discussion.........................................................................................27
1.4.5. Conclusion.............................................................................................................................31
1.5.IMPROVING LOAD MODULATION CAPABILITY OF IGCC BY COPRODUCING METHANOL..............32
1.5.1. Design and simulation of IGCC coproduction with methanol..............................................33
1.5.2. Analysis of load modulation capability in cogeneration.......................................................35
1.5.3. Conclusion.............................................................................................................................38
PART 2: GUIDELINES FOR CARBON CAPTURE AND GEOLOGICAL STORAGE IN
CHINA....................................................................................................................................................39
2.1.POTENTIAL CANDIDATE CO2 SOURCES FOR CCS IN CHINA..........................................................39
2.2.CO2 CAPTURE................................................................................................................................40
2.2.1. Post combustion CO2 capture...............................................................................................40
2.2.2. Pre-combustion CO2 capture................................................................................................43
2.2.3. Main economic performances..............................................................................................48
2.3.CO2 TRANSPORT............................................................................................................................48
2.3.1. Basic physical principles for CO2 pipeline transport...........................................................49
2.3.2. Component standards for the CO2 stream by pipeline transport.........................................50
2.3.3. Design, construction and operation of CO2 transport pipelines..........................................51
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4. 2.3.3.1 Design of CO2 pipelines....................................................................................................51
2.3.3.2 Construction of CO2 pipelines...........................................................................................52
2.3.3.3 Operation of CO2 pipelines...............................................................................................52
2.3.3.3.1 Monitoring of CO2 pipeline during operation................................................................52
2.3.3.3.2 Emergency mitigation and accident remediation............................................................53
2.4.CO2 STORAGE................................................................................................................................54
2.4.1. Introduction...........................................................................................................................54
2.4.2. Risk assessment and accident mitigation measures..............................................................61
2.4.3. Implementation process of a CO2 geological storage projects............................................64
2.5.OTHER CCS GUIDELINES SUPPORTING STUDIES.............................................................................64
2.5.1. Early action of CCS for China..............................................................................................64
2.5.2. CO2 source sink matching....................................................................................................84
2.5.3. Lab construction---CO2 property and pipeline corrosion property measurement, and LIBS
coal property online measurement..................................................................................................92
2.5.4. Dynamic simulator of Tsinghua oxygen staged gasifier.......................................................96
2.5.5. Simulation and economic assessment of polygeneration with CO2 capture.......................111
LIST OFAPPENDICES......................................................................................................................115
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5. Part 1: Polygeneration systems study
1.1. Model shelf of unit models for polygeneration system
Aspen plus system is one of the standard software for flowsheet simulation in the process
industries. It is supported by strong databases, complete sets of modules, and flexible simulation
tools. However, some complex unit models in polygeneration systems, such as air separation unit,
catalytic reforming reactions, may take time to be made appropriately on Aspen plus platform by
using its built-in modules, especially for those who are not Aspen plus experts. Therefore, the
purpose of this work is to develop a “model shelf” filled with self-defined modules built for
various applications to make it easy for any one who wants to build up a polygeneration
simulation model. In this report, unit models that comprise a typical Methanol-Power
polygeneration flowsheet are described. This is a step forward compared to previous works in
flowsheet simulation of polygeneration systems. Details of the work may be referred to our new
book on polygeneration, (see appendix A.)
1.1.1. Gasifier modeling
Although different gasifier models have been developed in the past years, gasifier modeling
continues to be a challenge. Selecting a gasifier model depends on the accuracy and robustness
desired for the model, Gibbs reactor, in which the chemical products are calculated based on a
minimization of Gibbs free energy for all possible species. was used as the core model to build
typical types of entrained-flow gasifiers such as GE slurry feed gasifier and Shell gasifier, as
shown in Figure 1-1. Depends on different syngas cooling process, different gaisifer unit model
have been developed, which are all lumped parameter models and able to predict final gas
compositions.
Figure 1-1 Gasifier unit
5

6. 1.1.2. Air separation unit
In a typical air separation unit, the air that has been induced in is compressed to a pressure
around 6 bars. Heat is created as a result. The compressed air is first cooled down to a temperature
of minus 180°C. As it expands in the separation columns, it cools down still further. As a result it
liquefies to some extent (the temperature being lower than the boiling point), cooling and
separating. By means of the separation column, the air is separated into its components, which is a
purely physical process, not involving any chemical reactions. The gas products oxygen and
nitrogen with high purity of about 95% are discharged at elevated pressure.
Figure 1-2 Air separation unit
1.1.3. Gas purification units
Typical units of the syngas purification process consist of Rectisol unit and N-Methyl
Diethanol Amine (MDEA) absorber.
The raw syngas fed to the Rectisol Unit is to remove sulfur compounds and COS from the
gas stream. The Rectisol Unit utilizes cold methanol to purify the gas. First, the gas in the unit is
washed with medium-cold methanol to remove gas naphtha components, i.e., pentanes, hexanes,
benzene, toluene, and heavier aromatics. The pre-wash methanol stream is then flashed to release
dissolved gases. The flashed gases are routed to the Sulfur Recovery Unit. The pre-washed gas
exiting the pre-wash column is routed to the main wash column where the bulk of the H2S and CO
are removed by washing with very cold methanol. After the main wash column, the gas is finally
washed in the fine wash column where the H2S content of the gas is reduced to less than 0.1ppmV
6

7. Figure 1-3 Rectisol unit
MDEA process for CO2 removal is one of the best available processes to meet the specific
plant conditions of high CO2 purity, minimum H2 loss, no corrosion, low energy requirement and
low capital investment. Water and MDEA (C5H13O2N) solution are used as the liquid washing
agent as H2S is highly soluble in it. This operation removes H2S by means of an MDEA water
solution that absorbs acid species in a syngas stream. Figure 1-4 shows common layout of MDEA
unit on our “model shelf”.
Figure 1-4 MDEA unit
1.1.4. Water gas shift reactor
Water gas shift process is almost unavoidable in polygeneration systems, which is usually
7

8. used to adjust the Hydrogen/carbon ratio of the syngas for downstream process. The water shift
reaction is equilibrium limited, which implies that the extent of CO concentration is dependent on
the temperature in the shift reactor. The CO concentration is thermodynamically favored at lower
temperatures, although catalyst activity is generally higher at higher temperatures. Coal
gasification leads to a relatively high CO concentration in the syngas, which results in a large
steam requirement both to meet the minimum inlet steam/CO-ratio needed to protect the catalyst
and to enhance the equilibrium conversion. The steam flow can also be used as a diluent to limit
the adiabatic temperature increase in a previous shift term reactor.
Previous studies indicated that staged injection of synthesis gas and quench water between
reactors could potentially reduce the overall steam requirement. The CO concentration is
simultaneously enhanced by staged addition of reactants combined with the corresponding
temperature quenches. Therefore different schemes of water gas shift unit are developed to
investigate in detail the impact of water gas shift on system efficiency. Figure 1-5 shows two
typical layouts for water gas shift unit on the “model shelf”.
Figure 1-5 Two configurations of water gas shift unit
1.1.5. Methanol synthesis and distillation
Methanol is considered as an important product of polygeneration system. We developed a
simulation model through a kinetics model of the ASPEN plus, which has the capacity to detect
operating characteristics of Methanol synthesis. The calculated results are in fair agreement with
the actual operating data. Figure 1-6 illustrates the Methanol synthesis unit and Figure 1-7 shows
the distillation tower of methanol.
8

9. Figure 1-6 Methanol synthesis unit
Figure 1-7 Methanol distillation unit
9

10. 1.2. Advanced system simulation platform with integration of Aspen Plus &
GTpro
During the last two decades, there has been a tremendous development of software for
modeling and simulation process or energy systems. The energy system is getting more complex
due to the quality of the product, controlling pollutant generated from the energy system, etc.. A
higher level of integration processes and optimization of processes increase the need of accurate
information about the behavior of a system.
No single tool simulates all types of systems. Different domains have different needs in
terms of material properties, types of problem to be solved, special input or output, etc.. Some
energy system may need to combine the simulation process of different simulators under one
framework. For example, the chemical process and power plant process.
Often one tool is not possible to handle problems in all domains. But by combining two or
more tools from different domains, one can handle the interdisciplinary problems. The main issue
is to develop the scheduler which could invoke the tools properly and correctly. For large and
mature software, a set of interfaces are always provided for users to operate the models or extend
the functionality. One possible solution for combining tools from different domains is to generate
a scheduler manually. This scheduler implements the interfaces provided by these tools to interact
with the different domains models in these tools. This approach could be straightforward and
efficient if the dataflow for these tools was simple. But the complexity of constructing such a
scheduler is increased if complex models are provided.
Aspen Plus is a leading process modeling tool for conceptual design, optimization, and
performance monitoring for the chemical, polymer, specialty chemical, metals and minerals, and
coal power industries. GT Pro automates the process of designing a combined cycle or gas turbine
cogeneration plant. GT Pro is particularly effective for creating new designs and finding their
optimal configuration and design parameters. We propose an integration approach for Aspen Plus
and GT Pro for power plant processes. Details of the Aspen plus and GT pro connector can be
referred to Appendix B.
1.2.1. Purpose
The purpose of this connector is to combine chemical processes and power plant processes
together, designing next generation clean power plant in an integrated model-based environment.
Combined Cycle power plant has great impact even in today’s power generation. The investment
to this field is increasing, especially in developing countries. Integrated Gasification Combined
Cycle (IGCC) can generate more electricity with less pollutant emissions, less water consumption.
The cost of power generation can be reduced and the efficiency can be improved.
Aspen Plus can be used for IGCC and design and optimization, and GT Pro can be used for
CCGT design and optimization. Aspen Plus and GT Pro should be used together for the simulation
process respecting the combined cycle.
10

11. But Aspen Plus and GT Pro can not be simply connected since the interaction is not the same
if the target models are different. Even in the same models, the interaction varies if the simulation
purpose is changed. Also, a mass of chemical materials, physical variables and model constraints
makes the interaction configuration difficult. That means it cost a lot of effort to move to two new
interaction models.
1.2.2. Software Integration Framework
The new software for this integration is named “AspenGT”, which combined from the names
of the two software. This software is consists of two components:
1) scheduer, a component for scheduling the simulation process.
2) connector. a component for connecting with Aspen Plus and GT Pro. This component can
access data of Aspen Plus and GT Pro, and can start them as separated processes and exit
the processes.
Figure 1-8 AspenGT
Steady-state solutions of valid models with proper inputs can be obtained by using Aspen
and GT Pro. Each software tool has its internal methods to solve for the solution. If the two
software tools are simply connected, one can model the software tools with valid models as two
functions as shown in below:
y = F(x)
x = G(y)
where x and y are n- and m-dimensional vectors. First equation represents Aspen Plus, second
equation represents GT Pro. However, by just connecting two software tools together, one can not
make them working together directly.
Consider a simple case with a loop. It can be simply written as x = F(x). If the function F(:)
is known explicitly, x can be solved by solving the optimization problem x-F(x) = 0. But the
function F(:) (or G(:) ) is unknown. So we propose an iterative method to solve this problem.
The other way to solve for the x=F(x) is to solve for the fixed point of the following
problem:
x[k + 1] = F(x(k)) (x(0) = x0; k = 0; 1; 2; 3 : : :)
In this mathematical formulation, there is no need to know the function F(.) explicitly but
11

12. only to evaluate F(.). And computes iteratively the least fixed point x, if exists. The problem can
also be interpreted as introducing a “delay” for each variable in the loop within the framework of
the Discrete-Event (DE) MoC. The idea can be simply extended to system with multiple functions
by introducing more delay elements. Since the DE MoC is an abstraction for asynchronous
systems, the evaluation of the functions do not have to evaluate at the same time but the ordering
of evaluation should be strictly preserved. Therefore, one only needs to come up with the right
scheduler and interface for putting two software tools together.
1.2.3. Example
A case study is presented in this section, which uses an Aspen Plus model and a GT Pro
model. The target in this case study is to find the exact amount of the gas mass flow for the Aspen
model, so that the byproduct fuel flow generated from Aspen Plus can be used in gas turbine in GT
Pro model. And the amount of the byproduct should be the exact amount that GT Pro needs.
Figure 1-9 shows Aspen Plus model.
AspenGT is consisted of two components. One component is AspenGT connector and
another one is the scheduler. The connector can interact with Aspen Plus and GT Pro, respectively.
It can also drive them to compute with the input flows and output flows.
Figure 1-9 Flowsheet in Aspen plus
Using E-LINK in Excel, GT Pro model can be imported. A table that shows the input and
12

13. output variables from GT Pro model will be generated. For the variables Fuel flow, Steam flow
and Water flow, there is one line for each of them, showing their amount, as shown in Figure 1-10.
Figure 1-10 E-LINK in Excel
The list shown below is the steps of using AspenGT Connector:
1. Initialize the input gas flow of Aspen Plus model.
2. Drive the Aspen Plus to start the simulation.
3. Get the output flows of Aspen model, including the fuel flow (named FUELGT Flow) and
the steam flow (named STGT Flow), and then set these two flows to the GT Pro model as its input
flows.
4. Drive the GT Pro to compute, and then compare the amount of the input fuel flow and the
required amount of the input fuel flow which GT Pro model actually needed.
5. If the amount of input fuel flow does not satisfy the required amount then set the input gas
flow of the Aspen model by changing the original amount of gas flow with the step size. Go to
step 2.
6. If the amount of input fuel flow satisfies the required amount then the process terminated.
All the streams in the aspen model can be imported in the streams box. Users can select the
streams from the streams list box as the input streams or output streams of Aspen Plus. Parameters
of input data and output data are optional.
After the input and output streams are specified, AspenGT Connector allows users to open an
excel file which is generated by the GT Pro via E-Link. The data of input and output streams will
be stored in the excel file. AspenGT Connector can drive Aspen and GT Pro to compute
iteratively.
13

14. Result of the interaction after the iteration process is terminated; a popup dialog box shows
the total iteration steps and the corresponding flow variables for each iteration. The complete
termination condition for the iteration process consists of two issues:
1. The difference between the current output data of both Aspen Plus and GT Pro and the
previous output data is less than the tolerance.
2. The difference between the output fuel flow of Aspen Plus and the input fuel flow of GT
Pro is less than the tolerance.
The termination condition considered in this example is only the second issue mentioned
above, because it is not a close loop example.
Figure 1-11 Iteration process
Two charts shown in Figure 1-11 are generated by AspenGT Connector, displaying the trends
of GAS, FUELGT, and GT FUEL mass flow. These two charts show the final computed FUELGT
mass flow which satisfies the expected amount with a tolerance.
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15. 1.3. Gas turbine performance with syngas fuel
Gas turbine is a key component in polygeneration systems. It also has great impact on the
overall system performance. Gas turbines are typically designed and optimized for the operation
with standard fuel, such as natural gas. Operation with syngas fuels, which is exactly the situation
for polygeneration systems, the engine performance will be affected to a varying extent,
depending on how different for the syngas from the design fuel. From the viewpoint of system
performance, when a low-heating-value fuel is used, which carries large quantities of inert ballast,
more fuel has to be added to the combustion system, so the mass flow in the turbine expander will
increase. An increased mass flow, at a certain temperature and properties, can only be forced into
the turbo machinery at the expense of increased pressure. If the pressure ratio becomes too high,
there is a risk of encountering compressor instability as well as other threats such as insufficient
blade cooling, rotor cooling, deterioration in component efficiency, etc. In the present study,
investigation was focused the overall performance of gas turbines, and component adaptation was
not to be addressed.
Measures of air bleed and fuel dilution are commonly adopted for a gas turbine fired with
syngas fuel. Air bleed refers to extracting air from the gas turbine compressor. It reduces the flow
through the turbine expander and therefore reduces the extent of modifications required to
accommodate increased volumetric flow through the expander and fuel systems. It also moves the
mass flow ratio between the compressor and expander closer to its design-point value. Fuel
dilution refers to re-injection of compressed nitrogen (waste nitrogen, diluent) from the air
separation process into the fuel gas prior to combustion. The main purpose of the syngas dilution
is to control combustion stability (flash-back) and NOx-formation.
Dedicate studies on syngas fired gas turbine have been done by many investigators, mainly
focused on full load performance. However, part-load performance of gas turbines with syngas
fuel, especially quantitative analysis, is not sufficiently illustrated. In the present paper, the steady-
state part load performance of syngas fired gas turbine was investigated. The main objective is to
quantify the variation in gas turbine performance with syngas fuel over a wide GT load range, and
to identify the controlling parameters or key boundary conditions in part load operation. The
impact of variable inlet guide vane (VIGV), the degree of fuel dilution and integration are
addressed.
The gas turbine considered for the current study was based on ALSTOM GT13, a
representative E-class gas turbine. It is to be noted that the gas turbine performance data on ISO
condition used in this paper were not the latest guarantee data. However, as a comparative
assessment between natural gas and syngas fired gas turbines, it was considered valid to depict the
general trends of the overall performances and to illustrate the impact of variable inlet guide vane
(VIGV), the degree of fuel dilution and system integration.
1.3.1. Gas turbine modelling
The general gas turbine model was built using the software EES. The model consisted of
compressor, combustion chamber and turbine. Other components such as diffusers, intake and
15

16. exhaust pipes were illustrated as pressure loss valves, as shown in Figure 1-12.
Figure 1-12 Structure of gas turbine model
Compressor and turbine characteristic maps were used in the off-design model. The surge
margin of compressor was defined by the following equation:
1 100% const flow@SL
OL
SM
π
π
 
= − × ÷
 
where SM represents the surge margin， π is the compression ratio, subscript “SL” denotes the
surge line and “OL” the operation line.
The relationship of turbine mass flow and pressure ratio were descried by the dimensionless
criteria：
0 0 0
0 0
m T Rm TR
p pγ γ
=
&&
where m& is the turbine inlet mass flow rate (kg/s)， p is the turbine inlet pressure (bar)；T is the
turbine inlet hot gas temperature (K) ； R is the gas constant (kJ/kg-K) ； γ is the adiabatic
exponent of the hot gas；The subscript “0” denotes the design-point value.
At the design-point of the gas turbine, the cooling air mass flow was calibrated by hot gas
temperature, hot gas mass flow and turbine blade temperature; while at off-design point, the
cooling air mass flow clm was determined by cooling air temperature clT , the pressure of the
compressor bleeding point upp and turbine inlet pressure downp ：
16

17. 2(1 / )up up dow
cl cl
n
m T
const
p p p
=
−
1.3.2. Specification of boundary conditions
The main operational boundary conditions of the gas turbine of interest were identified as
follows:
1) Turbine blade temperature shall not exceed its design-point value;
2) Compressor outlet temperature shall be not more than 40o
C higher than its
design-point value;
3) Turbine outlet temperature shall be not more than 30o
C higher than its design-
point value;
4) Compressor surge margin.
As mentioned previously, in the application of syngas fired gas turbines, for combustion
stability, NOx formation and IGCC system integration concerns, the syngas is usually diluted with
inert gas such as nitrogen. And the diluted syngas usually has a low heating value ranging from
4000 kJ/kg to 12000 kJ/kg. In order to study the impact of the syngas composition and heating
value on the operation characteristics of the gas turbine, two different kinds of syngas were used in
the present study with the compositions shown in Table 1-1.
Table 1-1 Composition of syngas fuel
Undiluted CO-rich syngas Diluted CO-rich syngas
Mass Vol. Mass Vol.
O2 0.00% 0.00% 0.00% 0.00%
N2 8.66% 6.22% 48.42% 39.65%
CO2 2.21% 1.01% 1.25% 0.65%
H2O 0.13% 0.15% 0.08% 0.10%
CH4 0.02% 0.03% 0.01% 0.02%
H2 3.09% 30.87% 1.75% 19.87%
CO 85.89% 61.72% 48.50% 39.72%
LHV 12397 kJ/kg 11137kJ/m3
7000 kJ/kg 7166 kJ/m3
1.3.3. Results and discussion
1.3.4.1 Predicted performances with natural gas
The operation window of a natural gas fired gas turbine was first calculated as a baseline for
17

18. later discussion, as shown in Figure 1-13. All the parameter data therein except VIGV angles
referred to the variation from its design-point value at ISO base load. Turbine inlet temperature
(TIT) was plotted in red, turbine blade temperature (Tbl) in black, compressor outlet temperature
(TK2) in pink and VIGV angles in blue. The predicted operation points at derated load were
indicated in black points.
- 2 5 0
- 2 0 0
- 1 5 0
- 1 0 0
- 5 0
0
5 0
Changeinflametemperature[C]
4 0 6 0 8 0 1 0 0 1 2 0 1 4 0 1 6 0
P o w e r o u t p u t [ M W ]
O p e r a t io n W in d o w ( N a t u r a l g a s , I S O c o n d it io n )
T A T
C O N S T R A IN T
VIGVCLOSED
VIGVOPEN
T IT C O N T R O L
T
b l C O N S T R A IN T
TK2CONSTRAINT
1 5 % S U R G E M A R G IN
Figure 1-13 Operation window of gas turbine fired with natural gas
By illustrating the main performance parameters, Figure 1-14 presented the following
features of the gas turbine operated with natural gas,
 There are two independent parameters mainly determining the operation point of the gas
turbine: VIGV angle, which specifies the compressor inlet air flow and combustion chamber
flame temperature, which is related with fuel flow rate and cooling air distribution in the
combustion chamber. Once the VIGV angle and the flame temperature are specified, the
other parameters are also determined, that is, the operation point of the gas turbine is fixed.
Within a certain load range, different combinations of the IGV angle and combustion
chamber flame temperature may lead to the same gas turbine output, which means that there
are more than one regulation methods to reach the same gas turbine load.
 Turning down VIGV from 0 to -30 degree while keeping combustion chamber flame
temperature constant (i.e. horizontally moving from right to left in the operation window in
Figure 1-14), we observed that the compressor surge margin was enlarged, the power output
was lowered, and the turbine outlet temperature TAT was raised, which was due to smaller
compressor inlet mass flow and lower pressure ratio of the engine; meanwhile, the turbine
inlet temperature TIT and blade temperature Tbl were derated. That’s because the ratio of
turbine cooling air flow rate and the hot gas flowrate was conserved, but the cooling air,
which was drawn from the compressor outlet, had a lower temperature, therefore the cooling
of the turbine blade was enhanced and the blade temperature was reduced.
 With VIGV turned down from 0 to -30 degree and turbine inlet temperature TIT kept
18

19. constant (i.e. moving from right to left along the red line in the operation window in Figure
1-14), the dominant boundary condition changed from turbine outlet temperature to the
compressor inlet mass flow rate.
 The area surrounded by the curve ABCDEFG represented the feasible region of gas turbine
operation. For a gas turbine combined cycle, in order to reduce the turbine load without
deteriorating the efficiency of the bottom cycle, the gas turbine outlet temperature should be
kept high enough, that is, it is favorable to reduce the gas turbine load along the upper border
of the operation window (curve ABCDE). From Figure 1-14, the variations of main
parameters during the part-load operation were obtained. When the load was lowered to 80%,
VIGV should be turned down with identical TIT; when the load was to be further lowered to
40%, VIGV regulation and identical TAT control mode should be used. Both lowering TIT
temperature and turning down VIGV angle would reduce the efficiency of gas turbine single
cycle, but the former measure has a greater impact. Therefore, even for gas turbine simple
cycles, which do not need to maintain a relatively high turbine outlet temperature, priority
may still be given to VIGV regulation method in the part-load operation of the gas turbine.
The operation strategy of the gas turbine combined cycles is more complicated than that of
the simple cycle, so in the following analysis only the former was to be addressed.
1.3.4.2 Predicted performances with syngas
Figure 1-14(a) showed the operation window of gas turbine fueled with diluted carbon-rich
syngas. Syngas was diluted with nitrogen, and had a lower heating value of 7000 kJ / kg. Notable
features of gas turbine operation were summarized as follows:
 With syngas fuel, the gas turbine operation point was determined by two contour lines:
0IGV = and 0Tbl∆ = , and main constraint was the gas turbine blade temperature
Tbl. Provided that the combustion chamber flame temperature remained unchanged, on
the one hand, due to a lower heating value of the fuel and a fixed compressor inlet air
flow rate, an increased fuel mass flow rate was required to maintain an identical flame
temperature, that is, the hot gas mass flow of the gas turbine would rise as well as the
heat flux of the turbine expander; on the other hand, because of the fixed through-flow
capacity of the turbine expander and increased hot gas flow, there was an increase in the
compressor pressure ratio and in compressor outlet temperature (by about 20o
C), that is,
turbine cooling air temperature would inevitably increase, leaving the turbine expander
challenged by insufficient cooling and overheating threat. If the gas turbine was to be
operated with the same turbine blade temperature as its design-point, the combustion
chamber flame temperature had to be lowed by 60o
C in syngas operation, and the
turbine inlet temperature TIT had to be lowed about 22o
C, as shown in Figure 1-14(a).
 When the gas turbine was operated at its full capacity, due to the fixed compressor inlet
mass flow and significantly greater pressure ratio, the operation point of the compressor
was elevated, moving closer toward its surge line. Another consequence was that the
turbine outlet temperature TAT was decreased by about 20o
C, which was caused by a
19

20. lower turbine inlet temperature TIT and a greater turbine expansion ratio. In addition, the
gas turbine output was boosted by 16.6% than its design-point value.
 Differing from the operation strategies with natural gas, the load regulation region of
identical TIT mode was observed to be widened while the regulation scope of identical
TAT mode to be narrowed. The main reason is: to keep TAT temperature constant, both
the turbine compression ratio and turbine inlet temperature TIT have to be either
increased or decreased. With syngas operation, when TAT temperature reached its
maximum, the identical TAT control mode was activated and VIGV was already
positioned to its minimum value, leaving less scope for the variation of the turbine
compression ratio. As a result, the working region of identical TAT control mode was
shrinked.
- 2 5 0
- 2 0 0
- 1 5 0
- 1 0 0
- 5 0
0
5 0
Changeinflametemperature[C]
8 0 1 0 0 1 2 0 1 4 0 1 6 0 1 8 0 2 0 0 2 2 0
P o w e r o u tp u t [ M W ]
O p e r a t io n W in d o w ( d ilu t e d s y n g a s )
L H V = 7 0 0 0 k J / k g = 7 1 6 6 k J / m 3 , A ir b le e d r a t io = 0 %
S U R G E
L IN ET A T C O N S T R A IN
VIGVCLOSED
VIGVOPEN
T I T C O N T R O L
T
b l C O N S T R A IN
TK2CONSTRAIN
8 % S U R G E
M A R G IN L IN E
- 2 5 0
- 2 0 0
- 1 5 0
- 1 0 0
- 5 0
0
5 0
Changeinflametemperature[C]
6 0 8 0 1 0 0 1 2 0 1 4 0 1 6 0 1 8 0 2 0 0
P o w e r o u t p u t [ M W ]
O p e r a t io n W in d o w ( d ilu t e d s y n g a s )
L H V = 7 0 0 0 k J / k g = 7 1 6 6 k J / m 3 , A ir b le e d r a t io = 5 %
8 % S U R G E M A R G IN L IN E
T A T
C O N S T R A IN
VIGVCLOSED
VIGVOPEN
T IT C O N T R O L
T
b l C O N S T R A IN
TK2CONSTRAIN
Figure 1-14(a) GT Operation window with diluted CO-
rich syngas without air bleed from compressor
Figure 1-14(b) GT Operation window with diluted CO-rich
syngas with 5% air bleed from compressor
Figure 1-14(b) showed the situation when the compressor air bleed was adopted to improve
the working condition of the engine. The bladed air from the compressor can be supplied to the air
separation system in an integrated IGCC system. As shown in Figure 1-14(b), 5% air bleed
improved the compressor surge margin, compared with the operation window in Figure 1-14(a). In
addition, the cooling of the turbine blade was also enhanced, so that the TIT temperature didn’t
have to be lowered as much, though this impact was not significant. When the gas turbine was
operated at its full capacity, the power output was increased by 8% than its design-point value.
The valid range of identical TAT control mode was from 53% of load to 72% of load, an enlarged
scope compared with that in Figure 1-15(a).
Gas turbine performance fired with undiluted syngas was shown in Figure 1-15(a) and
Figure 1-15(b). The comparison of Figure 1-14 and Figure 1-15 suggested that using undiluted
syngas could enlarge the gas turbine operation window.
1. First of all, the turbine blade cooling was enhanced remarkably. To ensure that the
turbine blade was not overheated, TIT temperature was only required to drop about 10o
C
20

21. at full load without air bleed, and about 5o
C with 5% air bleed.
2. Secondly, the compressor surge margin was enlarged. Without air bleed, the surge
margin was greater than 8%, and with air bleed, the surge margin was close to 15%.
3. Thirdly, the valid range of identical TAT control mode was extended: in the case without
air bleed, it was from 51% of load to 77% of load, in the case without air bleed from
39% to 78%. This implied that in a wider load range, the exhaust gas of the gas turbine
could be kept at a high temperature, which was beneficial for the efficiency of the
bottom cycle.
- 2 5 0
- 2 0 0
- 1 5 0
- 1 0 0
- 5 0
0
5 0
Changeinflametemperature[C]
6 0 8 0 1 0 0 1 2 0 1 4 0 1 6 0 1 8 0
P o w e r O u t p u t [ M W ]
O p e r a t io n W in d o w ( u n d ilu t e d s y n g a s )
L H V = 1 2 3 9 7 k J / k g = 1 1 1 3 7 k J / m 3 , A ir b le e d r a t io = 0 %
8 %
S U R G
E
M
A R G
IN
T A T
C O N S T R A IN
VIGVCLOSED
VIGVOPEN
T IT C O N T R O L
T
b l C O N S T R A IN
TK2CONSTRAIN
- 2 5 0
- 2 0 0
- 1 5 0
- 1 0 0
- 5 0
0
5 0
Changeinflametemperature[C]
4 0 6 0 8 0 1 0 0 1 2 0 1 4 0 1 6 0
P o w e r o u t p u t [M W ]
O p e r a tio n W in d o w ( u n d ilu t e d s y n g a s )
L H V = 1 2 3 9 7 k J /k g = 1 1 1 3 7 k J / m 3 , A ir b le e d r a t io = 5 %
S U R G E M A R G IN
T A T
C O
N S T R A IN
VIGVCLOSED
VIGVOPEN
T IT C O N T R O L
T
b l C O N S T R A IN
TK2CONSTRAIN
Figure 1-15(a) GT Operation window with undiluted CO-
rich syngas without air bleed from compressor
Figure 1-15(b) GT Operation window with undiluted
CO-rich syngas with air bleed from compressor
However, undiluted syngas has very limited capacity to boost the power output, since the
lowering of turbine inlet temperature TIT offsets the impact of increased fuel mass flow in an
almost equivalent extent. The combination of compressor air bleed and syngas undilution may
even result in a smaller power output than its design-point value. This finding implied that, from
the concerns of power output and overall efficiency, in partially integrated IGCC system, where
some air is bleed from the gas turbine compressor to feed air separation unit, the nitrogen is
recommended to be injected back to dilute the syngas fuel.
1.3.4. Conclusion
Part load analysis of gas turbines operated with syngas fuel was performed, leading to some
useful conclusions. It is found out that the main constraints of a conventional gas turbine fueled
with syngas are insufficient cooling of the turbine blade and the shrinked compressor surge
margin. The lower the heating value of the syngas fuel, the further the operation point of the gas
turbine would depart from its design-point, and the more the combustion flame temperature had to
be reduced.
Generally speaking, air bleed from the compressor is beneficial for improving the working
conditions of the gas turbine fired with syngas. The lower the heating value of syngas, the more
21

22. remarkable this improvement is expected to be. From the concerns of power output and overall
efficiency, in partially integrated IGCC system, where some air is bleed from the gas turbine
compressor to feed air separation unit, the nitrogen was recommended to be injected back to dilute
the syngas fuel
22

23. 1.4. An integrated catalytic CO2 / CH4 reforming approach to dual fuel MeOH
and power polygeneration
1.4.1. Introduction
In this paper, a “dual fuel” gasification based MeOH and power polygeneration system
featured by an integrated catalytic CO2 / CH4 reforming approach without water-gas-shift reaction
is introduced. CO and H2 are produced through catalytic reforming between CO2 and CH4. The
ratio of carbon to hydrogen, which is required by the follow-up chemical synthesis, can be
adjusted by different combinations of CO2 rich gasification gas and CH4 rich coke oven gas. By
this way, the gasification gas avoids the water-gas shift reaction to adjust the radio of carbon to
hydrogen and catalytically reforms with the coke oven gas, which effectively increases the amount
of effective gas. Thereby this scheme achieves the following purposes: full use of coke oven gas,
reduction of CO2 emissions, and reduction of system energy loss.
To obtain a comprehensive understand of the feature of dual gas polygenenration system,
ASPEN Plus and GT Pro programs are utilized to simulate the 1.2×108
–3.2×108
kg methanol and
274–496 MW power polygeneration system. The system’s technology scheme, operating
parameters, and efficiency are analyzed and evaluated to reveal the relationship of materials and
energy and the best co-production coupled configuration. The data and results obtained will be
used for building industrial device.
1.4.2. System scheme
Fig.1-16 dual fuel polygeneration flowsheet
Figure 1-16 is the methanol-power polygeneration system flow diagram. Gasification coal
with vapor and oxygen mixture enters into the ash-agglomerated gasifier. Raw gasification gas is
generated in reactor at 3 MPa with a carbon conversion ratio around 95 percent, and the
23

24. agglomerated ash is removed in the solid-form. The high-temperature raw gas (about 1084 )℃
flows into the waste heat boiler to generate 14.2 MPa, 538 high-pressure superheated steam℃
and 3.3 MPa medium pressure saturated steam for the steam turbines of the power generation part.
Gas is cooled to 371 , and enters the high-temperature purification devices, where ZnFe℃ 2O4 is
used as the high temperature desulphurization agent to remove H2S and COS from gasification gas
to the required level for direct burning.
Coke oven gas from the coking process is compressed to the pressure of gasification gas, and
enters a normal temperature purification process. A certain proportion of the coke oven gas and
gasified coal gas are mixed, through the gas saturation and pre-heater to 600 , entering℃
autothermal reforming reactor. There CO2 and CH4 of the mixture auto thermal reform under the
catalysis of carbon, make (H2-CO2) /(CO + CO2) in the synthesis gas raise to around 2.05; the
outlet temperature of products after the transformation is about 1000 ; syngas heat transfers in℃
gas preheater, and then enters into the waste heat boiler 2. Here 3.3 MPa medium Pressure
Saturated Steam is generated and the syngas is further cooled down to 60 . Then syngas re-℃
enters medium-temperature fine desulfurization to make the sulfur content in synthesis gas meet
the requirements of chemical synthesis.
To meet the pressure requirements of the chemical synthesis, the synthesis gas after
purification is compressed to 6.6 MPa into liquid methanol synthesis reactor, and synthesizes in
the 250 isothermal conditions, by one through. Reaction heat given off, by the use of a heat℃
exchanger, produces 3.3 MPa medium Pressure saturated steam for the steam turbine power
generation; the methanol-rich gas after reaction is cooled to 40 , and then enters the gas-liquid℃
separator. The crude methanol solution obtained after throttle enters the three towers distillation
units to be pure methanol products; unreacted gas gets recollected by expansion and mixes with
the high-temperature purification gas to be used as gas turbine fuel.
1.4.3. Modeling of core equipment: autothermal reforming
Through CH4-CO2 reforming reaction to adjust the ratio of hydrogen and carbon, main
reaction:
CH4+CO2=2CO+2H2, H298= 247.4 kJ/mol.△
Since this reaction is a strong endothermic process, it could adopt the autothermal partial
oxidation process. Under catalysis of carbon, through CH4 and CO2 reforming reaction (about
3000 kPa, about 1000 ), CH℃ 4 and CO2 are converted into CO and H2.
1.4.3.1 Autothermal reforming technology schemes and
principles
Coke oven gas and gasification gas both could be used for synthesis gas’ raw materials, but
24

25. ratio of effective components H2 and CO should be appropriate. The composition of coke oven gas
and gasification gas is as shown in Table 1-2. Both are not appropriate to be directly synthesized
to methanol, but can be adjusted by way of catalytic reforming introduced above.
Table 1-2 The composition of coke oven gas and gasification gas (vol.%)
H2 CH4 CO CO2 N2
coke oven gas 58.10 24.90 5.86 2.35 3.90
gasification gas 42.49 0.04 29.07 21.04 7.23
Autothermal partial oxidation conversion technology is a partial oxidation process that
provides heat for reaction system, then mixture after oxidation enters catalyst layer to carry
through CH4 and CO2 reforming process under catalysis.
Autothermal partial oxidation conversion reactor is composed of combustion chamber and
reaction chamber. In the combustion chamber, gasification gas, coke oven gas and O2 mix in
appropriate proportion and partially combust, then enter the reaction chamber to further react into
synthesis gas. But if coke oven gas is used as the only raw material, with its large number of H2,
the main combustion reaction is (1). This is because that combustion rate of H2 is 1000 to 100
million times of the rate of the other reactions, far greater than the CH4 and CO combustion rate,
that is, at the top of combustion chamber room, the combustion of hydrogen a O2 is the main
reaction, generating H2O and a great amount of heat. In the combustion process, a small
proportion of CH4, and CO combustion (2)–(5) may be accompanied.
H2 + 1/2O2 = H2O, H△ 298 =-241.0 kJ/mol; (1)
CH4 + 2O2 = CO2 + 2H2O, H△ 298 =-802.6 kJ/mol; (2)
CH4 + O2 = CO + H2 + H2O, H△ 298 =-278.0 kJ/mol; (3)
2CH4 + O2 = 2CO + 4H2, H△ 298 =-71.2 kJ/mol; (4)
CO+1/2O2=CO2, H△ 298 =-110.52 kJ/mol. (5)
When gas mixture after burning reaches the catalyst layer of Reaction Room, almost all the
oxygen is consumed. Main reactions in the catalyst layer are showed below:
CH4 + CO2 = 2CO + 2H2, H△ 298= 247.4 kJ/mol; (6)
CH4 + H2O = CO + 3H2, H△ 298= 206.4kJ/mol; (7)
CH4 + 2H2O = CO2 + 4H2, H△ 298= 165.4 kJ/mol; (8)
C + H2O = CO + H2, H△ 298 =-36 kJ/mol; (9)
C + CO2 = 2CO, H△ 298 =-519 kJ/mol. (10)
The characteristics of ‘dual fuel’ auto-thermal reforming process are: making use of both①
the coke oven gas and CO2; compared to steam conversion, saving a lot of water; based on② ③
carbon catalyst, lowering the requirements of feed gas; coke oven gas no needing deep
desulphurization and purification, and without catalyst S poisoning issues; no carbon④
deposition poisoning problem.
25

26. 1.4.3.2 Aspen simulation of autothermal reforming process
Due to the complexity of the process, dynamic equations under the relevant catalyst have not
yet been obtained. But basing on the calculation of the reactions’ equilibrium constant, it is not
difficult to find under the conditions of such a high temperature (> 1000 ) and pressure (> 3℃
MPa), the reactions all reach the thermodynamic equilibrium very quickly. Therefore, study here
focus on, through the Gibbs model, finding the relationship between product components and raw
materials, the ratio of coke oven gas and gasification gas, the Volume of O2, etc.
Calculation will take 100 kmol/h gasification gas as a benchmark, controlling the methane
concentration in synthesis gas of 1% to 5% (dry mole-rate) through changing the flow of oxygen,
and regulating the ratio of hydrogen and carbon by controlling the flow of coke oven gas.
Combinations:
(1) Gasification gas and coke oven gas are premixed, mix with oxygen, partially combust in
the combustion chamber, and then get into the reformer.
(2) Gasification gas, after partial combustion, gets into the reformer with coke oven gas.
(3) Coke oven gas, after partial combustion, gets into the reformer with gasification gas.
Calculation results show that in combination (2), meeting the requirement of methane
concentration and the ratio of hydrogen to carbon will make the combustion chamber temperature
above 3000 , a temperature materials cannot stand. As a result, here we only compare (1) with℃
(3).
Table 1-3 Comparison of fuel gas flux and outlet temperature of reformer for the different combinations
Methane
content*
/%
Combination (1) Combination (3)
Coke oven gas/
(kmol•h-1
)
Oxygen /
(kmol•h-1
)
Outlet temp.
of reformer/
℃
Coke oven gas/
(kmol•h-1
)
Oxygen /
(kmol•h-1
)
Outlet temp.
of reformer/
℃
1 341.5 67 1145 337.7 66 1145
2 329.5 60 1096 327 59 1096
3 317.2 54 1067 317.5 54 1067
4 311.4 50 1046 310.9 50 1046
5 306.9 46 1029 305.3 46 1028
Table 1-3 lists the conditions of getting suitable synthesis gas content for methanol, ratios
among gasification gas, coke oven gas and oxygen. According to the results, with the increase of
methane content in the synthesis gas, the amount of required coke oven gas and oxygen is on the
decline. The results of two combinations are similar, mainly due to reaction balance. In the system
26

27. simulation combination (1) will be used.
1.4.4. Simulation results and discussion
Gasification coal in this study is bituminous coal of Shanxi BinXian. Its proximate analysis,
ultimate analysis and high calorific value are showed in Table 1-4.
Table 1-4 Analysis of Shanxi BinXian Coal
Proximate analysis Ultimate analysis Qad,net,p /
(kJ•kg-1
)Mad Vad FC Aad Mad Had Oad Nad Sad Cad Aad
2.52 24.43 62.91 10.14 2.52 3.85 12.73 0.36 0.46 69.94 10.14 27685
1.4.4.1 System simulation results and analysis
Through the above calculation, on the scale of 1822×103 kg/d gasification, while 80 percent
of gasification gas for electricity generation, the other 20 percent with coke oven gas adjusting
hydrogen-carbon ratio and using slurry reaction one through ethanol-aether synthesis technology,
and un-reacted gas for power generation, the following results are observed by this paper: “dual
fuel” polygeneration scale is an annual output of 216400 tons’ methanol and 359.33 MW’s net
electricity output. Auxiliary power consumption includes air separation, reforming oxygen
compression, coke oven gas compression, syngas compression, gasification oxygen compression,
injected nitrogen compression and other auxiliary equipment, etc., the total consumption of raw
materials and by-products being shown as Table 1-5.
Table 1-5 Total output and consumption of dual fuel polygeneration system (300 days available per year)
Material Product
Gasification coal/
(106
kg•d-1
)
Coke-oven
gas/(m3
•d-1
)
Oxygen /
(m3
•d-1
)
Power
/MW
Methanol /
(108
kg•a-
1
)
Gross
power /
MW
Net
power /
MW
Sulfur /
(106
kg•a-1
)
1.822 2698330 1342727 78.42 2.164 437.75 359.33 2.3913
1.4.4.2 Unit process simulation results and analysis
The results of Unit process’ key equipment parameters and operating parameters are shown
in Table 1-6. Cold gas efficiency of ash-agglomerated gasifier is lower, and the reason of using it
is mainly that about 20 percent CO2 generated in syngas react with CH4 in coke oven gas; air
separation unit uses external compression process; electric power consumption only refers to the
power consumption of air compressors. Purity of oxygen product is 99.7% and the pressure is
0.135 MPa, nitrogen product being mainly used for transporting dry pulverized coal and injection
to gas turbine.
Table 1-6 Key unit process modeling result
27

28. Ash-agglomerated gasification Methanol synthesis and rectify
Item Value Item Value
Pressure /MPa 3 Temperature/℃ 250
Temperature /℃ 1084 Pressure /MPa 6.6
Mass ratio of oxygen to coal 0.68 Reforming oxygen compress
work/MW
4.19
Mass ratio of steam to coal 1.7 syngas compress work/MW 6.67
Gasifier oxygen compress work/MW 7.23 (CO+H2)conversion rate (mol)/% 38.7
Nitrogen compress work/MW 2.83 Methanol content (mol)/% 15.2
Carbon conversion rate/% 95 Crude methanol yield/(t•h-1
) 30.33
Valid gas content (Vol)/% 71.6 33bar steam yield/(t•h-1
) 29.1
Ratio of oxygen to syngas/(m3
•10-3
m-3
) 193 Tail gas turbine work/MW 3.70
Ratio of oxygen to coal/(kg•10-3
m-3
) 405 Rectify callback rate/% 99.1
LHV efficiency/% 74.1 Rectify heat duty/MW 18.96
HHV efficiency/% 81.6
Air separation GTCC
Item Value Item Value
Oxygen callback rate/% 92.8 Fuel flux/(kg•s-1
) 55.73
Oxygen /(m3
•d-1
) 1342727 Fuel LHV/(MJ•kg-1
) 12.25
Including : gasification/(m3
•d-1
) 474533 Nitrogen compress work/MW 7.81
Reforming /(m3
•d-1
) 868194 Gas turbine gross power/MW 278.91
Nitrogen /(m3
•d-1
) 1331265 Steam turbine gross power/MW 155.14
Consumed power/MW 23.73
1.4.4.3 The impact of methane conversion rate on system performance
The combination of features of gasification gas rich in carbon and coke oven gas rich in
hydrogen needs compression of coke oven gas and consumption of a large amount of pure oxygen.
So in order to get a reasonable assessment of weather it can really improve system performance
process itself, the nature of fuel and other aspects all should be assessed. Through above systems
simulation datum, system energy yield is defined to (Energy receipts-Energy consumption) /
Energy income, of which income is the result of the use of coke oven gas, while consumption
comes from compression, oxygen generation and reforming process.
Figure 1-17 shows methane conversion rate’s effect on system energy yield. Seen from the
28

29. map, if methane conversion rate of auto reforming process gets higher, system energy yield gets
better. But when the methane conversion rate is lower than 0.53, from the perspective of fuel use,
the system has no income.
Fig. 1-17 Methane conversion rate’s effect on system energy yield
1.4.4.4 Characteristics of the system revealed- discussion of key parameters split
ratio’s effect on system efficiency
(1) Dual fuel Polygeneration system’s efficiency analysis
Due to the coupling between gasification and chemical industry, chemical industry and power as
well as gasification and power, the “Dual fuel” Polygeneration system becomes very complicated.
By calculating each separate equipment’s energy balance to derive the system’s thermal efficiency,
will not only be a huge workload, but also lose their universal application of calculation and
comparison. To simplify for a universal comparison, the “dual fuel” Polygeneration system will be
divided into: gasification island, chemical island and power island, and definition of system low
calorific value efficiency is
MeOH MeOH
coal coal COG COG
LHV Power
LHV LHV
m
m m
η
× +
=
× +
.
Through the efficiency analysis of various units’ process, it’s found that:
g MeOH g c pη η η η η η= × + × ×
where, LHV―low calorific value, kJ/kg; m―mass flow, kg/h；Power―kW; gη ―low calorific value
efficiency of gasification island; cη ―low calorific value efficiency of chemical island; pη ―low
calorific value efficiency of power island; MeOHη ―low calorific value conversion efficiency of
methane; MeOH―methanol; COG―coke-oven gas.
As heat value loss in the chemical island is only caused by methanol synthesis, and heat
29

30. value loss in the power island is only caused by power generation, in order to directly describe the
valid efficiency of methanol production and electricity, according to the above derivation, we get
the following two effective efficiencies:
MeOH MeOH
vMeOH
coal coal COG COG p g
LHV
LHV LHV Power
m
m m
η
η η
×
=
× + − ×
,
( )vPower
coal coal COG COG MeOH MeOH c MeOH g
Power
m LHV m LHV m LHV
η
η η η
=
× + − × +
.
(2) Discussion of gasification gas split ratio’s effect on system efficiency
It’s defined that ratio of gasification gas directly used for power generation of gasification to
the total gasification gas volume is the split ratio. Under the circumstances of a fixed amount of
coal, by changing x to study the impact on the system efficiency, the results are shown in Fig.1-18.
It can be seen from the diagram, as the split ratio increasing, the quality ratio of coal gasification
to coke oven gas (“coal-char ratio") is gradually increasing too. System efficiency reduces after
the first increasing, at a maximum 0.487 when the split ratio is 0.8, its corresponding coal-char
ratio being 1.53; This is because as the coal-char ratio increases, the consumption rate of auxiliary
power grows quicker while the increase rate of methanol and power production become slower,
the two of which make system efficiency of "dual fuel" polygeneration system reach the
maximum at the split ratio of 0.8. Heat value ratio of the two products, Methanol and power,
(referred to as “chemical-power ratio”) also decreases after the first increase, at a maximum 0.516
when the split ratio is 0.65, its corresponding coal-char ratio being 0.87. This is mainly because
with coal-char ratio’s increase, the change rate of methanol and power production is not the same.
Evidently, “dual fuel” polygeneration system at the circumstances of a fixed amount of coal,
with the changing split ratio, has best system efficiency. At this point, the corresponding volume
of coke oven gas could be acquired, and further the scale of methanol and electricity production
could be determined.
Figure 1-18 Relation between split ratio and system efficiency, chemical-power ratio and coal-char ratio
The results of further calculation on system efficiency, methanol synthesis effective
efficiency and power generation effective efficiency are shown in Figure 1-19. It is not difficult to
30

31. find from the graphic, with the split ratio increasing, each efficiency is in the trend of first
increasing and then decreasing. When the split ratio is 0.8, each efficiency reaches its best value.
Figure1-19 Split ratio’s effect on system performance
1.4.5. Conclusion
A “dual fuel” methanol-power Polygeneration system scheme is designed, with production
of 120–320 kilotons methanol and 274–496 MW power.
The core process of “dual fuel” polygeneration - auto reforming is comparatively studied, the
technology combinations being determined, and the suitable ratio among gasification gas, coke
oven gas and oxygen for methanol synthesis being acquired.
Under the conditions of methane conversion rate of coke oven gas higher than 53%, the
system can make a better income; so, “dual fuel” polygeneration system has advantages of
improving system performance as well as making full use of coke oven gas.
“Dual fuel” polygeneration system at the circumstances of a fixed amount of coal, with the
changing split ratio, has best system efficiency. Its corresponding volume of coke oven gas, after
being determined, will help define the scale of methanol and electricity production.
31

32. 1.5. Improving Load Modulation Capability of IGCC by Coproducing Methanol
Integrated gasification combined cycle (IGCC) is considered as one of the most promising clean coal power
generation technologies. Since 1970s many developed countries led by the United States have invested large amounts
of funds for its development. From the successful demonstration of the Cold Water Power Plant until now, US, Europe
and Japan have already had IGCC power plants that are commercially operated. In recent years with the awareness of
the global warming crisis, more attention has been paid to the potential of IGCC in CO2 mitigation. China has begun
IGCC studies very early, but currently there are still no IGCC demonstration power plants available, which greatly
hinder the development of China's IGCC technology. At present with the increasing rising prices of oil and natural gas,
some oil / gas-fired combined cycle power plants begin to consider an IGCC alternation to lower the high fuel costs;
what’s more, more stringent emissions regulations of power plants have been implemented, which offers new
opportunities of IGCC power plant construction in China.
Currently the major factors that hinder the development of IGCC are the economic performance and reliability.
Due to the high investment, low fuel cost and inflexibility of gasification process, it is generally believed that IGCC
plants should be operated in base load. However, the capability of load modulation is usually required by electricity
grids, therefore once IGCC is operated in part load, the defect of poor economic performance and narrow scope of load
modulation becomes even more prominent. IGCC coproduction of methanol, namely, coal based polygeneration,
provides an approach to address the issue.
The structure of a polygeneration system is shown in Figure 1-21, where the dashed lines represent optional
couplings between each unit. Polygeneration system is a complex system with the coupling of power generation and
chemical process. Some studies have been done on the performance and energy-saving mechanism of polygeneration
systems, and the findings show that the polygeneration system has remarkable advantages over the pure IGCC system
in economic, energy and environment performances. However, current studies are mainly focused on the design point
operation. One critical issue that the polygeneration system has to be confronted with is: electricity grids require some
flexibility of the power generation to follow the load demand, while the traditional chemical system is supposed to
preserve stability in continuous operation; the two different operation manners coupled would definitely lead to a new
system with different operation characteristics. The study of the new operation characteristics of the polygeneration
system has significant importance for the industrialization of polygeneration in both maneuverability and operation.
Though China has already started polygeneration demonstration projects, there is little research reported in open
literature on the part load operation characteristics that aims at industrial reality, so it is far from enough to meet the
needs of the industry. As a result, it is urgent to carry out relevant study. As a first step, this paper tries to start the
research in this field.
Despite the increased complexity in operation and maneuverability, polygeneration provides the possibility to
enhance load modulation capability of IGCC systems and improve the economic performance in part load operation as
well. The reason is, when it is required to reduce the electricity load, the redundant syngas can be used for methanol
synthesis, which makes it possible to preserve the working condition of the expensive gasification unit, which counts a
considerably high fraction of the total plant investment (over 30% if ASU is included), at full load rather than part load.
Based on actual process data from industry, such as gasification and methanol synthesis, this paper simulates the
polygeneration systems with the chemical processes simulation software Aspen Plus and the gas turbine power plant
simulation software Thermoflux; case studies are examined to illustrate the increased operational flexibility of the
IGCC coproduction with methanol; furthermore, a preliminary analysis is given on how to tailor a polygeneration
system to satisfy the electricity load demand.
32

33. Figure 1-21 Configuration scheme of polygeneration system
1.5.1. Design and simulation of IGCC coproduction with methanol
The cogeneration system consists of the following three sections: gasification (air separation unit included),
power generation, methanol synthesis. After gasification, quench and cleaning, the syngas is divided into two parts
passing to methanol synthesis and power generation unit respectively, where Xm represents the ratio of the syngas
flowing to the power generation unit divided by the total amount of syngas (as shown in Figure 1). Power/chemical
ratio is defined as the ratio of the syngas for power generation to the syngas used for methanol synthesis, which is Xm /
(1-Xm). In the base case, the power/chemical ratio is set as 0.9 (close to 1) as a reference for system design and
simulation. The flow chart of the cogeneration is shown in Figure 1-21.
Load modulation strategy of the cogeneration system is to send the redundant syngas to the methanol synthesis
unit and to lower the load of power generation unit when keeping the operation condition of the gasification unit
unchanged. Since the capacity of the methanol synthesis unit is limited, how should a proper design capacity of the
synthesis unit in the coproduction system be chosen to meet the requirement of power load modulation? To address this
issue, three cases are designed and simulated with more details given in the following part. According to the common
operation practice in the gas and chemical industry, the analysis is based on the following three premises:
1） The load range of the methanol synthesis unit is 70%~110%;
2） The load range of the slurry gasifier is 70%~120%;
3） The stable load range of the gas turbine fired with syngas is 50%~100%
To facilitate the analysis, three parameters are defined as follows:
Design capacity of equipment: the design capacity
Design operation capacity of equipment: the rating capacity operated at design point
Capacity surplus percentage of equipment: the ratio of the difference between the design capacity and the rating
capacity operated at design point divided by the design capacity.
Three cases share the same system configuration and the same process sections. The gasification unit is based on
the GE slurry gasifier / quench design, the methanol synthesis process uses unconverted syngas recycling and the
power generation unit uses a GE 9171E gas turbine with dual-pressure steam cycle. The methanol synthesis reactors in
the three cases are identical but have different capacity surplus percentages. In case 1 there is no capacity surplus, that
is, the operation capacity of the equipment equals to its design capacity at the system design point with an annual
methanol output of 500,000 tons; in cases 2 the methanol synthesis unit has a capacity surplus percentage of 10% with
an methanol annual output of 450,000 tons; cases 3 has a capacity surplus of 20% with an annual methanol output of
400,000 tons. Case 1 is chosen as the reference case with power/chemical ratio at the design point of 0.9, which is
referred to as the “reference power/chemical ratio”, while Case 2 and Case 3 have the design power/chemical ratio of 1
and 1.1, respectively.
33

34. Figure 1-21 Parallel mode polygeneration system with recycling of unconverted syngas
1.5.1.1 Gasification unit
The gasification unit uses GE slurry-fed entrained flow bed gasifier, with gasifier pressure of 40 bar, slurry
concentration of 66.5% and gasification temperature of 1300℃. The composition of the coal used in the simulation is
listed in Table 1. The air fed to the ASU is supplied by air compressors, and the nitrogen produced is supplied to the
power generation unit for syngas dilution. The purity of the oxygen from the ASU outlet is 99.6%. After quench and
clean up, the syngas is further cooled to generate low pressure steam (7.9bar) , which is partly used as process heat in
methanol synthesis process and partly supplied to HRSG. The gas turbines used in the three cases are operated at
identical working conditions, while the amounts of methanol production are different, leading to different coal inputs of
3313t/d, 3109 t/d, 2935 t/d, respectively.
1.5.1.2 Methanol synthesis unit
Methanol synthesis unit is composed of syngas shift, sulfur removal, carbon removal, sulfur recovery, methanol
synthesis and methanol rectification. After desulfurization the sulfur content can be reduced to below 0.1ppm. The
methanol synthesis uses gaseous synthesis process; due to the recycling design, the amount of purge gas is so small that
it is fired directly rather than sent to the power generation unit. The methanol synthesis equipments in the three cases
are identical: two reactors with an annual methanol output of 250,000 tones for each. In case 1, when the cogeneration
system is operated at the system design point, the methanol synthesis unit is also operated at its design point, yielding
methanol 500,000 tons per year. In Case 2, when the cogeneration system is operated at the system design point, the
methanol synthesis unit is operated at part load with an annual methanol output of 450,000 tons. Case 3 has an
equipment capacity surplus of 20% in the methanol synthesis unit, with a methanol output of 400,000 tons per year.
Due to the different working loads of the synthesis reactors, the synthesis pressure slightly varies as 80bar, 76.6bar and
74.5bar with the aim to control the CO conversion ratio and to prevent overheating. The low pressure steam generated
during the methanol synthesis is used for process heat. The methanol synthesis reactor is simulated through the
programming of the macro-dynamic reaction equations.
34

35. 1.5.1.3 Power generation unit
The sulfur content of syngas for power generation is required to be below 25 ppm. After desulfurization the
syngas is saturated with hot water which is separated from the syngas cooling process in the gasification unit, after that,
the syngas is preheated by the high pressure hot water from HRSG. To make use of the high pressure, the syngas is first
expanded through an expander, then mixed with nitrogen from ASU, and finally fed into the combustion chamber of the
gas turbine. The diluted syngas has a low heating value of 5577 kJ / kg. All three cases use the GE 9171E gas turbine
with the design compression ratio of 12.3 and hot gas inlet temperature of 1124℃. The characteristics of the gas turbine
fired with syngas are calculated with compressor maps and flow matching formula. HRSG uses two-pressure steam
cycle with characteristic parameters of 56 bar/5.6bar/527℃/255℃. In part load operation, the gas turbine is regulated
by compressor inlet guide vanes (IGV) control and T3 control, and the steam turbine is operated on sliding pressure
mode.
Tab.1-8 Compositional characteristics of the coal（dry basis）
Proximate
Analysis
Moisture Fixed Carbon Volatiles Ash
0 49.46 43.22 7.32
Ultimate
Analysis
Ash Carbon Hydrogen Nitrogen Sulfur Oxygen
7.32 76.40 5.24 1.23 2.84 8.97
1.5.2. Analysis of load modulation capability in cogeneration
The simulation results of the three cases are listed in table 1-9. The design point stands for the performance
parameters at the design point of the cogeneration system. The lowest power load point is achieved when the load of
the power generation unit is reduced and the operation condition of the gasifier keeps unchanged but redundant syngas
is used for methanol synthesis (all the discussion below is based on this regulation approach). In case 1, based on the
premises as mentioned previously, the synthesis unit can handle a load increase of 10%. In case 2 and case 3, the
capacity surplus of the synthesis unit enables a load increase capability of 20% and 30% respectively. Table 2 also lists
the performance of IGCC, which has the same gas turbine combined cycle as the coproduction system and reaches its
lowest power load point when the gasifier is operated at 70% load.
Tab.1-9 Main performance of polygeneration systems and IGCC at design point and the lowest power load point
Case 1 Case 2 Case 3 IGCC
Design
point
Lowest
power
load
point
Design
point
Lowest
power
load
point
Design
point
Lowest
power
load
point
Design
point
Lowest
power
load
point
C1D C1OD C2D C2OD C3D C3OD IGCCD IGCCOD
Design capacity surplus
percentage of synthesis
equipment
0 10% 20% -
Coal input, t/d 3313 3313 3109 3109 2935 2935 1544 1111
Steam generation during syngas
cooling, kg/s
30.19 30.19 27.47 27.47 25.20 25.20 10.21 4.33
Syngas fraction for methanol
synthesis, %
53.44 58.78 50.38 62.64 47.43 66.35 - -
Power/chemical ratio 0.9 0.7 1.0 0.6 1.1 0.5 - -
Methanol production, kg/s 17.69 19.35 15.64 19.35 13.9 19.35 - -
Recycle ratio 4.5 4.55 4.9 4.55 5 4.55 - -
Space velocity, L(STP)/(kg*h) 7700 8519 7283 8522 6616 8519 - -
Compression work, MW 6.58 6.37 4.95 6.37 3.78 6.37 - -
Gas turbine output, MW 154.43 133.84 154.43 109.31 154.43 88.13 154.43 103.21
Steam turbine output, WM 85.29 80.81 84.69 66.58 83.46 54.04 79.78 49.75
Net power output, MW 161.56 139.36 164.14 108.52 166.19 81.66 201.55 122.70
35

36. Net thermal efficiency*，% 43.53 44.45 42.93 44.59 42.36 44. 67 36.64 30.9
Gas turbine load % 100 86.87 100 70.78 100 57.07 100 66.8
Power load，% 100 86.25 100 66.11 100 49.14 100 60.8
*net thermal efficiency is defined as: (net power output + methanol production x higher heating value of
methanol)/higher heating value of total coal input
From case 1 to case 3, there is a decline in the total coal input as well as the ASU power consumption. In addition,
due to the decrease of methanol production, the compression work of the synthesis unit also drops. Therefore from case
1 to case 3, there is a slight increase in net power outputs of three cogeneration systems at the design point, which are
161.6MW, 164.1MW and 166.2MW respectively. The IGCC system has a lower ASU compression work and no power
consumption in methanol synthesis process, resulting in a higher net power output than case 1 by 40MW.
Since methanol and electricity are of different energy quality, there is no generally agreed method to appropriately
illustrate the energy utilization of cogeneration system, so the present paper uses the thermal efficiency method with the
heating value of methanol. Figure 3 shows how the net thermal efficiencies of the coproduction and IGCC at the design
of point and at the lowest power load point relate with the syngas percentage used for methanol synthesis. Because the
methanol production system has a higher thermal efficiency (50%) than IGCC power generation system, the net
thermal efficiency of the cogeneration system is higher than that of the IGCC system. When it is required to lower the
power load of the cogeneration system, power/chemical ratio is reduced while the methanol production is increased,
thus improving the net thermal efficiency of the system. Figure 1-22 also illustrates that the net thermal efficiency of
the system shares the same trend as the syngas percentage for methanol synthesis, in addition, the higher the proportion
of syngas used for methanol synthesis, the greater the net thermal efficiency is. In part load operation the net thermal
efficiency of the IGCC system worsens significantly: when the power load is reduced to 60.8%, the net efficiency is
only 30.9%.
Figure 1-22 Net thermal efficiency of polygeneration and syngas fraction for methanol synthesis
In case 1, the methanol synthesis unit has no capacity surplus percentage in the coproduction system at the design
point, which can handle only 10% of load increase. If the operating condition of the gasification unit is kept unchanged,
there is limited capability for the power generation units to reduce the power output, and the lowest power load
achievable is 86.25%. In Case 2 and case 3, besides the load modulation capability of the power generation unit, the
methanol synthesis unit is designed to have a capacity surplus percentage of 10% and 20% respectively, making the
lowest power load achievable to be 66.11% and 49.14%. The IGCC system has its lowest power load of 60.8% when
the gasifier is operated at the load of 70%. Figure 1-23 compares the load modulation capabilities of the coproduction
system with different equipment capacity surpluses and the IGCC system, where the shadows of the column represent
the achievable range of power load modulation. The design capacity surplus percentage of synthesis equipment enables
certain load modulation capability without changing the operating condition of the gasification unit. When there is
enough design capacity surplus of the synthesis equipment (for example, case 3 with 20% of equipment capacity
surplus), coproduction system has a greater load modulation capability than the IGCC system, the latter one regulates
36

37. the load through the control of the gasification unit. As a result, when the power/chemical ratio is specified in the
cogeneration system, equipment capacity surplus percentage can be designed to achieve the electricity load range
required. When the load modulation capability of the synthesis unit reaches its maximum scope, a greater power load
range can be obtained through the load regulation of the gasifier.
60.8%
49.1%
66.1%
86.3%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
案例 1 案例2 案例3 I GCC
电力负荷百分数
Figure 1-23 Load range of polygeneration systems and IGCC
The analysis above aims at the cogeneration system when the power generation and chemical process are parallel
connected, where the syngas distribution ratio between chemical process and power generation unit (that is,
chemical/power ratio) close to 1:1 and the purge gas from the methanol synthesis unit is not used for power generation.
Apart from this type, the coproduction system can have various structural configurations, for example, when the
chemical/power ratio is 0, the cogeneration system is serial connected, where all the syngas is sent to the methanol
synthesis unit and the unconverted gas is used for power generation. The syngas distribution between the power
generation unit and the chemical synthesis may take the form of "big power generation, small methanol", for example,
the chemical/power ratio of 4.4 corresponds to the coproduction system with an annual methanol output of 100,000
tons and net power output of 180 MW; otherwise it would manifested itself in the form of "big methanol, small power
generation," for example, the chemical/power ratio of 0.4 corresponds to the system with an annual methanol output of
1 million tons and the net power output of 132 MW. The part load operation characteristics of cogeneration systems
with different configurations are to be further analyzed in another study.
Once the requirement of power load regulation scope is specified, power/chemical ratio has a significant impact
on the capacity surplus percentage of the methanol synthesis unit. Figure 5 illustrates the capacity surplus percentages
corresponding to the minimum power load achievable when the reference power/chemical ratio is 0.4, 0.9 and 4.4
respectively (The reference power/chemical ratio of the cogeneration system is the one when the capacity surplus
percentage of the synthesis unit is zero). For the systems with reference power/chemical ratio of 0.9(as previously
discussed), when the capacity surplus percentage of the synthesis unit is 27.2%, the minimal power load is 41% limited
by the load range of the gas turbine. When reference power/chemical ratio is 4.4 (which belongs to the “big power
generation, small methanol” type), the load modulation capability of the cogeneration system by varying the syngas
distribution between chemical process and the power generation to lower the power output decreases significantly;
even if the equipment capacity surplus percentage is 30%, the minimal power load achievable is only 88.1%. When
reference power/chemical ratio is 0.4 (which belongs to the “big methanol, small power generation” type), the minimal
power load achievable is 59.1% if there is no equipment capacity surplus, and 21% if there is an equipment capacity
surplus percentage of 8.6%, when the load of the gas turbine is 50%. As a result, the smaller the power/chemical ratio
is, the more remarkable the impact of equipment capacity surplus percentage on the load regulation capability would
be. When the power/chemical ratio is great enough, it is difficult to achieve large scale load modulation through
equipment capacity surplus alone, and then it is necessary to lower the load of the gasifier.
37

38. 0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0% 5% 10% 15% 20% 25% 30%
合成设备容量盈余百分数
最小发电负荷百分数 基础动化比=4. 4
基础动化比=0. 9
基础动化比=0. 4
Figure 1-24 Correlation between lowest power load and capacity surplus of synthesis equipments
1.5.3. Conclusion
The polygeneration system couples the IGCC system and methanol synthesis system that share the same
feedstock. When there is need to lower the power output, the gasification process unit, which takes a high proportion of
total plant investment, can be kept in full capacity operation, while the power output can be regulated by adjusting the
syngas distribution ration between the power generation unit and the methanol synthesis unit. If necessary, the load of
the gasifier can also be reduced to further increase the scope of load regulation. As a result, compared with the IGCC
system, the polygeneration system has a better economic performance and greater flexibility in part load operation.
Due to a higher thermal efficiency of the methanol synthesis process than the IGCC system, the polygeneration
system is superior to the IGCC system in thermal efficiency. The higher the power/chemical ratio is ， the more
remarkable the superiority of the polygeneration in net thermal efficiency would be. When the power load is reduced
while the operation conditions of the gasification unit is kept unchanged, the methanol production would increase,
resulting in an increase in thermal efficiency of the polygeneration system. It implies that the polygeneration system
can effectively avoid the poor part load performance in both thermal efficiency and economics, which is usually a
problem for the IGCC power plant. And because of the increased thermal efficiency, CO2 emissions in part load
operation can be reduced. Further analysis regarding the economic and emission characteristics of polygeneration
systems in part load operation will be discussed in another paper.
When the power/chemical ratio is specified, the capacity surplus percentage of the synthesis equipment can be
designed to enable some load modulation capability, with the aim to preserve the gasifier to its design capacity as close
as possible.
The power/chemical ratio at design point of the polygeneration system is a key factor that contributes to the load
modulation capability by adjusting the distribution ratio of syngas between the synthesis process and the power
generation unit. With the power/chemical ratio of 0.9, the capacity surplus percentage of the synthesis equipment is
27.2% to reach the minimum power load of 41%, while with the power/chemical ratio of 4.4, it is impossible to
regulate the power output in large scale by adjusting the synthesis process alone; hence the load adjustment of the
gasifier is necessary. The smaller the power/chemical ratio of the polygeneration system is, the greater the impact of the
capacity surplus percentage of the synthesis equipment on the power load modulation capability would be.
The requirement of load modulation has to be taken into consideration in the early stages of the system
preliminary design, and suitable power/chemical ratio and the capacity surplus percentage of the synthesis unit should
be properly chosen according to the range of power load regulation.
38

39. Part 2: Guidelines for carbon capture and geological storage in China
China has a huge CO2 emission, which is estimated to continue to increase with the future economy development
of China in the next few decades, therefore reducing CO2 emission is a severe mission faced by China in coming years.
CCS is thought to be a critical technology for CO2 emission reduction, especially for the countries or regions such as
China with coal, a carbon intensive fossil fuel, as the dominant primary energy source.
For these reasons, the Tsinghua-BP clean energy research and education center regarded CCS as a key research
topic and has conducted extensive researches on CCS. Studies of potential candidate CO2 sources for CCS
implementation in China, the physical mechanisms, technical performances, and economic performances related with
CO2 capture, transport and storage, were conducted and suggestion or guidelines for the actual implementation of each
step of CCS for China based on the previous analysis of various aspects of CCS were also provided as a joint research
program with world resource institute (WRI) sponsored by US department of state (See appendix C for details). The
techno-economic assessment of CO2 capture systems has also been accomplished under the support of EU-China
projects (COACH and NZEC), providing the priority of CO2 capture system development in China. The available
technologies for all the key facilities for CCS implementation in China, including ASU, gasifier, syngas cleanup, sour
gas shift reactor, acid gas removal, Clause sulfur recovery, hydrogen fired GT, chemical synthesizing units, CO2
compression &transport and storage, as well as the fundamental principals for geological storage of CO2 have also been
investigated by cooperation with Shenhua group and some practical solutions to utilize or reduce the CO2 and CH4
emission from Shenhua's coal chemical plants and coal mines have been proposed. By cooperating with GreenGen in
Tianjin, the Tsinghua-BP center is now working on a so called ADB project is to make a practical development
roadmap based on the achievements by closely cooperation of experts from all the key fields that are related to CCS,
including gasifier design, power system simulation and optimization, chemical engineering, pipeline design and
operation, geological survey and simulation, etc., and the aim of the roadmap is to facilitate and direct which can
facilitate the execution of the IGCC+CCS demonstraion project. Besides the strategy work for CCS, the Tsinghua-BP
center also started to build-up a brand-new lab for clean coal combustion and CCS key issues study. The laser induced
breakdown spectroscopy (LIBS) setup enables the center elemental concentration measurement and the high pressure
autoclave system enables the center to investigate the CO2 purity requirement from CO2 pipeline transport point of
view. The Tsinghua-BP center also start to work on a training simulator for a power plant with CCS, which would be
very important to study the dynamic and economic performance of a coal burning power plant with CCS system
attached.
2.1. Potential candidate CO2 sources for CCS in China
CO2 mainly comes from the combustion processes of fossil fuels in industry, such as power generation, coal
chemical industry, iron &steel, cement, etc, among which power generation industry holds the largest percentage of
CO2 emission, the CO2 emission of which takes almost half of all CO2 emitted around the world.
With the 30 years fast economy development, China has become the largest energy producing and second largest
energy consuming country around the world1
, with fossil fuels holding more than 80% of the total primary energy
consumption, which results in large amount of CO2 emission. Among all the major industry sectors that have large
amount of CO2 emission in China in 2006, coal power industry accounts for 2.3Gt, taking 40% of the total emission by
that year; besides, the emission amount of single plant is large, which is good for centralized emission reduction, so that
the fossil power industry is the industrial sector that has the largest CO2 mitigation potential among all sectors.
Secondly, one significant difference of China from other countries is that, most of the other countries produce primary
chemical feedstock using natural gas as the feeding, while China uses coal as the main feeding for primary chemical
feedstock production since China is lack of natural gas resources. A direct result of that is China owns the largest coal
1
人民网，2009 年 3 月 27 日。能源局：三年关停 3100 万千瓦小火电 http://energy.people.com.cn/GB/9036588.html
39

40. chemical industry around the world, which consumes more than 100 million tons of coal each year.2
Although the total
amount of CO2 emission from the coal chemical industry is not as large as that of the coal power industry, when
considering CO2 reduction, the coal chemical industry owns a unique advantage over the coal power industry: the CO2
concentrations of the flue gas from the coal chemical plants is much higher than that of the coal power plants, which
provides a precious opportunity for CO2 emission reduction with much lower cost than from power plants.3
Besides the
power industry and the coal chemical industry, there are some other important potential candidate sources for CO2
capture, including cement, iron &steel, etc. These industries altogether form the most important industries for CO2
emission reduction in China.
According to the actual situation of CO2 emission of China, and given comprehensive consideration to the factors
concerned with both CO2 reduction potential as well as cost, China should start capturing CO2 from the coal chemical
plants with large amount and concentrated coal chemical plants, and use the captured CO2 for enhanced oil recovery for
storage as well as economic revenue. Following the coal chemical industry would be the coal power industry with the
largest amount of CO2 emission and then the other large CO2 emitting industrial sectors such as cement, iron &steel,
etc.
2.2. CO2 capture
CO2 capture is the process to separate CO2 from the other components in the flue gas from the industrial plants to get
relatively pure CO2 stream for further treatment, transport and geological storage. Research on CO2 capture from flue
gas of power plants has been on for several years around the world, and is also the most mature technology category for
CO2 capture of all main industrial sectors, and CO2 capture from flue gases of other industrial sectors are quite similar
from the view point of physical mechanism, therefore we introduce the technologies of CO2 capture from power plants
as representative. Since China mainly relies on coal as the dominant primary energy source for power generation, here
we mainly talk about CO2 capture from coal fired power plants.
Basically, there are three ways for CO2 capture from flue gas of power plants, i.e. post-combustion CO2 capture, pre-
combustion CO2 capture and oxy-fuel combustion CO2 capture.
2.2.1. Post combustion CO2 capture
Post combustion CO2 capture process is for conventional coal or natural gas fired power plants. Since the basic
working mechanisms for CO2 capture from these two kinds of power plants are almost the same, here we mainly talk
about CO2 capture from the conventional powder coal-fired power plants.
2.2.1.1. Basic working mechanism and technical performances
The basic working mechanism of conventional powder coal-fired power plants is as follows. Coal is first grinded
into fine powder and then blown into the combustion chamber together with blown air. In the chamber, the coal is
combusted with O2 in the air, releasing huge amount of heat during the combustion process. A large amount of Flue gas
is also formed during the process, so that the temperature of the flue gas is significantly increased. Then the high
temperature flue gas formed during the combustion process exchanges heat with the water inside the water cooling wall
to form overheated steam in the drum, and then the overheated steam is sent to following steps for power generation.
The temperature of the flue gas is reduced during the heat exchanging process, after that it is sent to the flue gas
treatment units for impurities removal, such as particular, SOx, NOx, etc. In the end, the treated flue gas is emitted from
the powder coal fired power plant from the chimney.
To capture CO2 from the flue gas, a post combustion CO2 capture unit needs to be installed at the end of the flue gas
flow, in which the CO2 is separated from other components in the flue gas by chemical or physical means. The captured
2
中国能源统计年鉴 2007，中国国家统计局，中国发展和改革委员会，2007.
3
科技日报。http://lvse.sohu.com/20080729/n258439767.shtml
40

41. CO2 is then sent to following steps for dehydration and compression for further transport and storage, and the left
components in the flue gas (mainly N2 and a small amount of surplus O2) is released from the system as residual flue
gas. The simplified working flow of a post combustion CO2 capture system is shown in Fig.2-1.
Fig. 2-1 Simplified flow chart of powder coal fired power plant with post-combustion CO2 capture
The main components of the flue gas from conventional powder coal-fired power plants include a high concentration
of N2 (taken into the combustion system with O2 in the air), a small amount of surplus O2 which is not consumed during
the combustion process, CO2 (8~12% concentration, mainly formed during the combustion process), and small amount
of SOx, NOx and particular materials formed during the combustion process. Since the concentration of CO2 in the flue
gas is low, chemical absorption process is usually applied for separating CO2 from the other components, with MEA or
MDEA as the common absorption solvent. SOx and NOx are both sour gases, which can react with the chemical solvent
and cause inactivation of the solvent; besides, SOx, NOx and particular materials in the flue gas are important pollutants
to the atmosphere. Therefore, before sent to the CO2 separation unit, the flue gas out from the boiler should go through
a purification process to remove the these pollutants, to ensure the CO2 capture unit can work properly. The detailed
working mechanism of a chemical absorption unit is shown as Fig. 2-2.
Fig. 2-2 Detailed working mechanism of the chemical absorption process
The core components of the chemical absorbing unit for CO2 capture are two columns: the absorbing column is the
component in which CO2 is absorbed by the lean chemical solvent sprayed into it, forming rich solvent during this
process. The formed rich solvent is then sent to the steam stripping column to separate CO2 from the chemical solvent
to achieve recycle of the solvent. The recycle process of the chemical solvent needs large amount of high temperature
steam to heat the solvent, therefore this process is an energy-consuming intensive process. Usually, the high
temperature steam is extracted from the steam turbine unit in the power generation system, therefore the net power
41