Energy Conversion and Management 248 (2021) 114782

Contents lists available at ScienceDirect

Energy Conversion and Management

journal homepage: www.elsevier.com/locate/enconman

Thermo-economic analysis of integrated gasification combined cycle

co-generation system with carbon capture and integrated with absorption
refrigeration system
Adnan Muhammad a, Zaman Muhammad a, *, Atta Ullah a, Rizwan Muhammad b,
Neelam Ramzan a
a
Department of Chemical Engineering, Pakistan Institute of Engineering and Applied Sciences (PIEAS), Islamabad, Pakistan
b
Department of Chemical Engineering, College of Engineering, University of Bahrain, P. O. Box 32038, Isa Town Campus, Bahrain

A R T I C L E I N F O A B S T R A C T

Keywords: Greenhouse gas emissions have become a major issue during power generation from coal due to global warming
IGCC effects. Integrated gasification combined cycle (IGCC) power system has been acknowledged as a rare existing
Co-generation opportunity to utilize low-quality solid fuels with reduced emissions and co-generation of power, fuels and
Carbon capture
chemicals. Country like, Pakistan, where huge reserves of low-quality coal are present can benefit from this
Energy integration
technology. In this work, the steady-state thermodynamic and economic evaluation of IGCC co-generation system
Low-quality coal, Shell gasifier
has been performed for methane and ammonia production along with power generation. Gasification of coal has
been simulated using entrained flow Shell gasifier under thermochemical equilibrium with the Gibbs free energy
approach using local Thar lignite in Aspen Plus® V.11. The designs simulated include, IGCC 100% power with
and without carbon capture, and IGCC co-generation system with carbon capture with varied production of
methane, ammonia and electricity. Thermal efficiency, cost of electricity and CO2 avoided costs have been
evaluated for 100% power design. Total capital in the form of total overnight cost and operating cost (fixed and
variable) has been evaluated to account annualized expenditure for co-generation designs. Absorption refrig­
eration system (ARS) has been integrated with IGCC designs to meet the partial chilling requirement of lean
solvent in Selexol process, which caused the reduction in CO2 emission because of reduced auxiliary power
consumption. The net electrical efficiency of 100% power (design-2) is 32.33%, and the improved efficiency after
ARS integration is 32.61%. The performance of co-generation designs is evaluated by estimating annualized
revenue and annualized expenditures. One of the co-generation cases (design-4) with high methane, low
ammonia and medium electricity generation, showed better performance with respect to reduced GHG emissions
at almost same revenue to expenditure ratio as compared to design-2.

short term, India the second largest consumer of coal in the world after
China, has one of the highest potentials to increase coal consumption to
1. Introduction fulfill its electricity demands by 2025 [2]. Also, about 100 million tons
of coal gasification is the major focus of their policy by 2030 [2]. In long
Power generation at competitive and affordable price, and environ­ term, 2.5% increase in coal consumption is projected in power sector per
mental protection by reducing greenhouse gas (GHG) emissions are two year between 2018 and 2050 [3]. Similarly, China is projected to
main issues that modern world is facing. Fossil fuels are still contributing consume 39 quadrillion Btu of coal in electricity generation by 2050, the
a major role in most of the energy sectors for power generation. The second highest after renewables [3]. In context to Pakistan, beyond
major portion of electricity generation of several countries (e.g., China, 2021, 5 GW (GW) of coal-fired power plants mostly operating on do­
India, and Pakistan) depends upon oil, coal and natural gas. Globally, mestic lignite have been planned. Moreover, it is under consideration to
coal contributes around 40 % of total electricity generation [1]. The turn Thar lignite into liquid and gas fuels and fertilizers in the future [2].
huge consumption of coal in power generation, to fulfil industrial de­ In these scenarios, the utilization of coal in carbon-constrained way (i.e.,
mands by major economies of the world is predicted in the future. In

* Corresponding author.
E-mail address: zaman@pieas.edu.pk (Z. Muhammad).

https://doi.org/10.1016/j.enconman.2021.114782
Received 28 June 2021; Accepted 15 September 2021
Available online 15 October 2021
0196-8904/© 2021 Published by Elsevier Ltd.
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Nomenclature ARS Absorption Refrigeration System

ASU Air Separation Unit
Symbols BFW Boiler Feed Water
AER Annual Escalation Rate BWRS Benedict-Webb-Rubin-Starling
CCF Capital Charge Factor CCS Carbon Capture and Storage
CF Capacity Factor of Plant CEPCI Chemical Engineering Plant Cost Index
Cold Cold End CGE Cold Gas Efficiency
Exp Scaling Exponent COE Cost of Electricity
Hot Hot End DEPG Dimethyl Ether Polyethylene Glycol
h Enthalpy (J/kg) EP Elevated Pressure
m Mass Flow (kg/s) FYCOP First Year Cost of Production
MW h Megawatt Hours GE General Electric
OC Operating Cost GHG Greenhouse Gas
Q Heat Transfer Rate (kW) GT Gas Turbine
RC Reference Cost ($) HRSG Heat Recovery Steam Generator
RP Reference Parameter (indiv.) HHV Higher Heating Value
RY Reference Year HP High Pressure
SC Scaled Cost ($) HTA Heat Transfer Area
Scl Difference in Scaling and Current Year IGCC Integrated Gasification Combined Cycle
SP Scaled Parameter (indiv.) LCOE Levelized Cost of Electricity
SY Scaled Year LF Levelization Factor
TR Number of Trains in Reference LMTD Log Mean Temperature Difference
TS Number of Trains Scaled LP Low Pressure
U Overall Heat Transfer Coefficient (kW/m2.K) MAC Main Air Compressor
y Mole Fraction MHE Main Heat Exchanger
ΔT Temperature Difference (K) MP Medium Pressure
NETL National Energy Technology Laboratory
Subscripts NGCC Natural Gas Combined Cycle
ab Absorber O&M Operating and Maintenance
ammonia Ammonia Product PC-SAFT Perturbed-Chain Statistical Associating Fluid Theory
cond Condenser PEC Purchased Equipment Cost
electricity Electricity PLOX Pumped Liquid Oxygen
evp Evaporator PR Peng-Robinson
exh Exhaust Gas PR-BM Peng-Robinson Boston Mathias
exh, in Exhaust Gas In PSD Particle Size Distribution
exh, out Exhaust Gas Out RKS-BM Redlich-Kwong-Soave Boston Mathias
Fix Fixed SHE Solution Heat Exchanger
gen Generator TAC Total Annualized Cost
i Exhaust Gas Components TAEs Total Annualized Expenditures
ins Insulated TAR Total Annualized Revenue
j ARS Components TCI Total Capital Investment
methane Methane Product TIT Turbine Inlet Temperature
SHE Solution Heat Exchanger TOC Total Overnight Capital
Var Variable TPC Total Plant Cost
with cc With Carbon Capture T&S Transportation and Storage
without cc Without Carbon Capture WGSR Water Gas Shift Rector
Abbreviations WTA Wirbelschicht Trocknung Anlage
AGR Acid Gas Removal

controlled emissions) is the future of coal. The control on the emissions of huge amount of GHGs to reduce the
Some estimates show, over 50% of global coal reserves are of low impact of global warming simultaneously with energy supply at
rank, i.e., sub-bituminous and lignite [4]. Pakistan also has vast reserves affordable prices requires significant efforts in designing new systems of
of 175 billion tonnes of lignite coal, located in Thar Desert of Sindh. In coal based power generation. Integrated gasification combined cycle
addition to this, there are other lignite coal reserves in Lakhra, Sonda, (IGCC) power generation system is an emerging new technology which
Indus East coalfields in Sindh, Pakistan [5]. Huge emissions of GHGs offers efficient power generation due to possibility of co-firing (i.e.,
from coal combustion, such as carbon dioxide (CO2), are of major varying quality of coal with biomass), co-production (electricity,
apprehension. For the same amount of power generation, CO2 emission methane, ammonia, etc.) and ease of carbon capture [7]. The research
from coal is more than double as compared to natural gas [6]. Utilization performed by U.S. Department of Energy (DOE) investigated that IGCC
of low-quality coals, like lignite containing high sulfur contents becomes power plants are not just more efficient, but also more economical as
even more difficult for power generation. Vast reserves of cheap low- compared to pulverized coal power plants, when carbon capture is
quality coal can offer a sustainable solution for power generation, if considered [8,9].
their environmental impacts can be mitigated. In a scenario of US, replacement of all fossil fuel based combustion

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turbines was considered by coal based IGCC systems and natural gas co-generation included the electricity generation along with methanol
combined cycle (NGCC) plants. These new plants with carbon capture production. Economic evaluation of the co-generation was not consid­
and storage (CCS) can reduce GHGs to less than their set target of 784 ered by authors [19]. In [20], the U.S. Department of Energy (DOE)
million tonnes/year by 2050 [10]. It has been reported that, US may performed a techno-economic analysis of ammonia and methane co-
achieve their societal goal of cutting GHGs to less than 80 % of 1990 generation. The electricity generation was considered to meet the
levels by 2050, by making most of the electricity from IGCC plants with auxiliary power requirement via steam production during the process.
CCS. Installation of more IGCC + CCS to meet the goals of cutting GHGs Biomass based gasification processes for co-generation have also been
would increase the yearly capital cost for generators, hence a tradeoff is studied by number of authors [21–24]. Fan et al. [23] considered the co-
required [10]. The scenario to meet the GHGs reduction goal by 2050 generation of natural gas and power, based on coal and biomass gasi­
described above would require the introduction of more IGCC + CCS fication. Sahoo et al. [24] integrated biomass based gasification plant
plants during 2020 – 2030 [10]. Costs of power plants play an important with solar energy to make a hybrid system. Co-generation of power,
role in decision making to achieve GHGs targets, e.g., the coal based cooling and desalination was considered in their study.
IGCC plant costs more than a natural gas based plant. The increased In context to Pakistan, several previous studies [25–28] are available
costs of CCS reduces GHG emissions for both new alternatives i.e., on IGCC plants using different quality coals without any reference to co-
$1.44/kW per g/kW h saving in IGCC and $1.75/kW per g/kWh saving generation and ARS integration to the IGCC plant. The only develop­
for NGCC [10]. ment towards IGCC co-generation system in Pakistan was presented in
Co-generation from IGCC plants is a practical and viable design. The previous work [29]. Thermo-economic analysis of IGCC plant for the co-
main aim of co-generation process design is to increase the economic generation of ammonia, methane and power was performed in that
viability with reduced GHG emissions at the same time. Also, the co- study. Slurry feed gasification system was considered for coal gasifica­
generation increases the system flexibility in terms of multiple prod­ tion by assuming moisture free coal, which gives poor performance for
ucts, operation and feedstock [11]. Co-generation put additional benefit high moisture coal [30]. As a preliminary study, the detailed economic
in the installation of IGCC + CCS, e.g., production of hydrogen and analysis of co-generation system and net CO2 emission rate was not
electricity with CCS provides high return on the investment by selling considered in that study.
two products while meeting the GHG reduction target [10]. Chilling Studies of ARS integration with IGCC systems have also been re­
effect generated as a part of co-generation can cause a reduction in total ported in various articles [31–34]. In [31], chilling medium cooled by
auxiliary power of IGCC plant, like chilling of lean solvent in acid gas the evaporator of the ARS was used in the turbine inlet air chiller to
removal (AGR) section. Absorption refrigeration systems (ARS) are lower down the temperature of incoming air. Overall gas turbine (GT)
becoming more popular for being used in different cooling and chilling performance was slightly improved, especially during warmer days. In
applications because of almost zero global warming potential [12]. In that operation, the waste heat source was provided by CO2 compressors
this context, integration of ARS with power generating systems (e.g. that would otherwise not provide useful work. In such cases, an overall
IGCC) can fulfil the chilling requirements of the plant. Integrated ARS reduction in parasitic power loss is conserved. In the same study,
makes use of waste heat or low-quality heat from different components another ARS integration within the IGCC plant was highlighted, in
of the plant to create cooling effect, which can be used to cool different which waste heat from the CO2 compressors was utilized to drive the
components or streams of the plants. In this way, total efficiency of the integrated ARS, to cool the CO2 compressors using the compressor
plant can be enhanced and resultantly, specific CO2 emission to the coolers. Mazumder and Saha [32] integrated the diluent nitrogen (N2)
environment is minimized. compressor inlet cooling system of an IGCC with ARS. Low grade heat
The development of sustainable and efficient designs based on poly- from the heat recovery steam generator (HRSG) of the IGCC power
generation are encouraged by USA and many Western countries, since it system was utilized to power the ARS. It is a fact that for a given mass
is recognized as a strategic technology able to reduce GHGs [13]. flow, the power consumption of the diluent N2 compressor is higher at a
Numerous other countries (such as China, India, Saudi Arabia, etc.) higher temperature, because of high volume involved in the compressor.
aiming at the modeling of IGCC co-generation systems [14]. The liter­ Cooling the inlet N2 will cause it to get denser, hence requiring less
ature regarding IGCC co-generation investigations based on coal and compression power. The power consumption reduction of about 2 MW is
integration of ARS with IGCC systems have been presented in the possible by a reduction of the inlet temperature of diluent N2. By doing
following paragraphs. this integration the plant auxiliary load was reduced. Approximately 1
Li et al. [15] presented thermodynamic analysis of co-generation of MW to 1.8 MW output power was increased and 0.08%-0.12% net
methanol and power using coal partial gasification technology. Bose electrical efficiency gain was reported for an IGCC power plant.
et al. [16] carried out the performance assessment of a coal based co- After extensive literature review, the authors could not find any
generation for power and fertilizer. In their study, hydrogen produced research regarding the IGCC co-generation system with carbon capture
by the gasification of coal was used for power generation and urea based on low-quality coal and ARS integration to AGR of an IGCC for
production. CO2 required for the urea production was utilized by cooling provision of the lean solvent. To the best of author’s knowledge,
capturing the CO2 from the same plant instead of sequestering it, in this no studies are available in literature, which provide complete economic
way two-fold advantages of elimination of CO2 sequestration cost and evaluation of IGCC co-generation (e.g., power, methane and ammonia)
earning from additional product were achieved. A tradeoff between urea system for low-quality coal and complete economic analysis of inte­
production and power generation was drawn for maximum output [16]. grated ARS. As this work is the continuation of the previous study [29],
Li et al. [17] presented, a dual-gas source co-generation process which so the key novelty of this work represents, utilization of high moisture
used syngas from coal gasification and coke oven gas, as gas sources, and coal instead of moisture free coal in IGCC co-generation system along
co-produced dimethyl ether, dimethyl carbonate and methanol using an with ARS integration in AGR. For high moisture coal, dry feed gasifi­
integrated catalytic synthesis procedure. System performance was cation using Shell gasifier has been considered to assess the actual
evaluated by numerical simulation along with exergo-economic analysis conversion status of low-quality Pakistani lignite coal. IGCC 100%
of the co-generation process. power and co-generation systems powered by Pakistani lignite coal
Most recently, Li et al. [18] presented a conceptual design and the provide a baseline for the researchers working on local resources with
techno-economic analysis of a coal to natural gas and methanol based minimum environmental impact.
co-generation system. Authors emphasized that optimization of poly- The objective of this work is to evaluate the thermo-economic and
generation system has potentials for overall performance enhancement environmental aspects of power generation based on an IGCC co-
and reduction in cost. Heinze et al. [19] simulated a coal powered flu­ generation design with the aim of utilizing low-quality indigenous
idized bed gasification process to study the co-generation system. The coal in production of value added products. Thermodynamic models of

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Table 1 Table 1 (continued )

Simulation specifications in present work [8,41–43]. Process components Modeling blocks Parameter and value
Process components Modeling blocks Parameter and value
Sep, Heater, Reaction pressure: 33.62 bar
Coal Drying RStoic, Flash2 Compressor polytropic efficiency: 75% Compr
Compr Equilibrium temperature/pressure Methane compressor efficiency: 75%
110 ◦ C/1.1 bar (isentropic)
Heater Preheating of coal up to: 70 ◦ C Recycle compressor efficiency: 75%
Dried coal moisture content (weight): (isentropic)
12% Methane product pressure: 59.05 bar
ASU HeatX, Compr O2 purity: 95% (mole) ARS Evaporator temperature: 4.2 ◦ C (flue
RadFrac O2 pressure to gasifier: 51.02 bar gas), 6 ◦ C (hot water)
MheatX N2 (diluent) pressure: 26.48 bar Generator temperature: 86 ◦ C (flue
Main compressor efficiency: 84% gas), 80 ◦ C (hot water)
(isentropic) Condenser temperature: 35 ◦ C (flue
Inter-coolers temperature: 30 ◦ C gas), 38 ◦ C (hot water)
Gasification (Shell RYield (Reactor) Heat loss: 1% of thermal input Absorber temperature: 35 ◦ C (flue gas),
gasifier) 38 ◦ C (hot water)
RGibbs (Reactor) Gasifier pressure: 42.4 bar Absorption salt: LiBr
Gasifier exit syngas temperature:
1365 ◦ C
Syngas temperature after quenching:
232 ◦ C Table 2
Syngas cooling type: Water quench and Proximate and Ultimate analysis of Pakistani lignite coal.
syngas recycle quench
Coal Identity Thar Lignite Coal [52]
Carbon Conversion: 99.5%
WGSR RGibbs (Reactor) H2O to CO ratio: 1.8, CO conversion: Analysis type as-received dry basis
97.3%
Proximate analysis (wt %)
AGR Unit RadFrac Syngas inlet pressure: 34.3 bar
Moisture 44.92 0.00
Flash2 Recycle compressor efficiency: 75%
Fixed carbon 21.14 38.38
(isentropic)
Volatile matter 29.58 53.70
Lean solvent temperature at absorber:
Ash 4.36 7.92
10 ◦ C
Ultimate analysis (wt %)
H2S removal efficiency: 99.98%
Carbon 37.96 68.92
CO2 removal efficiency: 92%
Hydrogen 2.85 5.17
CO2 Sequestration Compr CO2 storage pressure: 153 bar
Nitrogen 0.46 0.83
CO2 compressor efficiency: 85%
Sulphur 0.31 0.56
(isentropic)
Oxygen 9.14 16.59
GT RGibbs GT air compressor efficiency: 86%
Ash 4.36 7.92
(Combustor) (isentropic)
HHV (kJ/kg) 15254.87 27695.84
Compr GT inlet temperature (TIT): 1324.5 ◦ C
GT outlet temperature: 566 ◦ C Calculated by Dulong formula [53].
GT efficiency: 88.60% (isentropic)
GT pressure ratio: 15.4 bar/1.05 bar
HRSG Pump, Compr, Pumps efficiency: 85%
HeatX
Table 3
Min. temperature approach: 10 ◦ C Cost functions for the PEC ($) evaluation of the components involved in ARS
Steam Turbine Pump, Compr HP steam turbine pressure ratio: 125.6 [63,63].
bar/40.54 bar Process Unit PEC ($) Year CEPCI
IP steam turbine-1 pressure ratio:
39.02 bar/6.89 bar Generator PEC = 130 × (Agen /0.093)0.78 2005 468.2
IP steam turbine-2 pressure ratio: 6.27 Absorber 2000 394.1
PEC = 16500 × (Aab /100)0.6
bar/3.08 bar
LP steam turbine pressure ratio: 3.08 Condenser PEC = 8000 × (Acond /100)0.6 2000 394.1
bar/0.048 bar Evaporator PEC = 16000 × (Aevp /100)0.6 2000 394.1
HP/IP/LP ST efficiency: 90.3/93.5/
SHE PEC = 130 × (ASHE /0.093)0.78 2005 468.2
88.2% (isentropic)
Inlet HP/IP steam temperature:
536.74 ◦ C
Condenser pressure: 0.048 bar IGCC 100% power generation design and IGCC co-generation (methane,
Flue gas temperature at stack: 143 ◦ C ammonia and power) designs have been presented to assess the first law
Cooling Tower Pump, Heater Cooling water range: 11.5 ◦ C
efficiency of the both type of designs. A detailed economic analysis for
Evaporative losses: 0.8% of circulating
flow/5 ◦ C of range both type of designs has been presented to estimate the financial impact
Drift losses: 0.001% of circulating of these designs. CO2 emission from IGCC 100% power and IGCC co-
water flow rate generation designs has been evaluated to assess the environmental
Cycles of concentration: 4 impact of these designs. Chilling based on vapor compression adds extra
Ammonia RGibbs Reactor pressure: 159 bar
GHGs in the environment. To reduce the GHG emissions, ARS has been
Production (Reactor), Sep
Flash2, HeatX, Reactor temperature: 427–507 ◦ C integrated with IGCC designs for the provision of chilling to the lean
Compr solvent in AGR. Waste heat recovered from the exhaust gas of HRSG and
N2 and H2 compressor efficiency: 84% hot water from the air separation unit (ASU) coolers has been utilized to
(isentropic)
power the ARS. Thermodynamic and economic analysis of ARS has also
Recycle compressor efficiency: 75%
(isentropic) been considered in this study to assess its complete financial impact and
Ammonia product conditions: − 25 ◦ C/ GHGs reduction. The input and economic parameters considered for the
131 bar simulations are given in Tables 1–3. An efficiency improvement of
Methane Production REquil (Reactor) Reactor temperature: 298.89 ◦ C 0.28% point is noted in base case (i.e., design-2) after integration of ARS
with IGCC plant. Design-4 with high methane production and medium

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 1. Schematic of IGCC (a) 100% power design-2 (base case) and (b) ARS integrated 100% power design-2A.

electricity generation is found to offer reduced GHG emissions with section.

almost equal revenue to expenditure ratio, as compared to design-2.
Also, Design-4 showed best performance in average and low selling
markets. This work is a continuation of our previous work [29], based on 2.1. Process description of IGCC system
moisture free coal and slurry feed gasification. IGCC co-generation using
dry feed gasification based on high moisture lignite coal performed in The configuration of IGCC system studied in this work consists of
this study, gives a realistic assessment about the indigenous resources of following main process areas: coal preparation, ASU, gasification, AGR,
Pakistan. syngas cooling and particulate removal, water gas shift rector (WGSR)
and combined cycle power generation, as shown in Fig. 1. Moreover,
2. Process description cogeneration designs have been presented in Fig. 2. Detail of these
process areas is presented as follows.
In this section, a brief description of the IGCC units considered in this
study has been presented. Operating principle and brief description of 2.1.1. Coal preparation
the ARS integrated with IGCC plant has also been provided in this For the dry-feed entrained flow gasifiers (e.g. Shell gasifier consid­
ered in this study), it is assumed that the lignite coal is dried to 12%

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 2. Schematic of IGCC (a) co-generation design-3, design-4 and design-5, and (b) ARS integrated co-generation design-3A, design-4A and design-5A.

moisture [8]. The Wirbelschicht Trocknung Anlage (WTA) technology gasifier of the IGCC plant has operated at HP. In this way, increase in
[8] has been used to dry the coal up to desired moisture level. The details IGCC efficiency and decrease in the size of equipment can be possible
of the Pakistani lignite drying using WTA technique can be found in [37].
previous work [35], flowsheet developed in Aspen Plus® is also pro­ An electric motor driven air compressor is used to discharge air at
vided in Appendix A. Conventional coal pulverizers, like roll mills are 6.9 bar. Some portion (31.25%) of air stream at 6.9 bar is compressed to
used to prepare feed for Shell gasifier, which likely results in an average 12.7 bar pressure and entered in HP column after exchanging heat in
coal size of 50–100 µm. main heat exchanger (MHE). The air supplied to the compressor is
assumed to be moisture free prior to the compression. Three compres­
2.1.2. Air separation unit sors with inter-stage cooling have been employed. In HP column liquid
Operating pressure of the ASU and the liquid or gaseous nature of the O2 and HP N2 have been separated as bottom and top product, respec­
output products mainly oxygen (O2) from the ASU are the main design tively. Both liquid O2 and N2 are supplied to the low-pressure (LP) col­
decision parameters. For IGCC plants, generally elevated pressure ASU umn and further rectified to produce 95%-pure O2 as bottom product
(EP-ASU) is used, since both the O2 and N2 are required at high pressures and LP N2 as overhead product. The O2 as liquid is pumped to a pressure
(HP) for the gasifier and the GT, respectively. Although, the power of 8.6 bar before leaving the ASU. Cooling of the HP air takes place
consumptions in the O2 and N2 compressors decrease in this type of ASU, during the vaporization of the liquid oxidant stream to be used in
the power consumption in the main air compressor (MAC) increases to gasifier. ASU is a big contributor (60–70%) in auxiliary power of the
balance the net impact. In addition, significant separation challenges IGCC plant [38].
can be faced due to decreased volatility in case of EP-ASU [36]. In this The LP N2 is compressed up to the GT combustor pressure using
study, a pumped liquid oxygen (PLOX) cycle has been chosen as the intercooled compressors, operating at 84% isentropic efficiency [39].

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 3. Flow diagram of dual stage Selexol process (Modified from [47] with permission).

Injecting N2 as a thermal diluent into the GT combustor has a number of particulate removal section. Solid gas separators, like cyclone and filters
advantages; decrease in NOx emissions due to decreased flame temper­ have been used to perform the duty. The syngas scrubber removes any
ature and increased power output due to enhanced flow are important to possible remaining particulates passing the filter further downstream.
mention [40]. The O2 product leaving the ASU is also compressed up to The un-reacted carbon, captured by cyclone or filter is recycled back to
the gasifier operating pressure using four intercooled compressors with the gasifier to achieve maximum conversion as shown in Fig. 1. The
an assumed isentropic efficiency of 84% [39], to discharge O2 at 51 bar. syngas particulate removal flowsheet compiled in Aspen Plus® is pro­
All product and system specifications of ASU are given in Table 1, and vided in Appendix A, along with drying and gasification of coal.
flowsheet of ASU simulation in Aspen Plus® is provided in Appendix A.
2.1.5. Water gas shift reactor
2.1.3. Gasification The CO in the syngas is shifted to CO2 by water–gas shift (WGS)
The Shell gasifier which is less sensitive to the quality of coal has reaction as shown in Eq. (1). Shifted CO2 is captured using pre-
been selected in this study [30]. The O2 with 95% purity is introduced combustion carbon capture technique (i.e., dual stage Selexol process),
into the gasifier along with pulverized and dried (12% moisture) coal. as shown in Fig. 1.
Entrained flow gasifier (Shell gasifier) has been selected in this study for
CO + H2 O⇌H2 + CO2 (ΔH o = − 41kJ/mol) (1)
the gasification of the coal. The operating temperatures are high in
entrained flow gasifier and ash slagging takes place during gasification. Catalyst de-activation by elemental carbon formation on the catalyst
The ash is removed from the bottom of the gasifier in a molten form. In is the main problem faced in WGS reaction, which can be overcomed by
these conditions, almost negligible formation of hydrocarbons, oils and maintaining a minimum steam to CO ratio in shift reactor [40]. Also, the
tars is observed. High carbon conversion is assumed (99.5%). Cyclones addition of steam helps to shift the equilibrium of the WGS reaction
and filters have been employed to remove and recycle back unreacted towards CO2. The WGS reaction is exothermic, two stages of WGSR have
carbon from the syngas, as shown in Fig. 1 (a) and (b). been used to accomplish the desired conversion of CO and intercooling is
The characteristics of coal, its proximate and ultimate analysis (see required to lower the syngas temperature. Shift steam at 288 ◦ C and
Table 2) dictate the performance of the gasifier and syngas composition. 41.4 bar is used in WGSR, and intermediate pressure (IP) steam at 41 bar
The outlet composition of syngas from the Shell gasifier was compared has been raised during the cooling of the syngas.
with the literature’s estimated value [8], which was in close agreement
and that approves the reliability of this work. The specifications and 2.1.6. Acid gas removal process (dual stage Selexol process)
operating parameters of the gasifier have been provided in Table 1 and The partial pressure of acid gas in the syngas of IGCC power plant is
Aspen Plus® flowsheet of gasification is presented in Appendix A with more in case of pre-combustion capture [8]. Therefore, physical solvents
drying of coal. are economical and attractive than chemical solvents. In this study, the
dual stage Selexol process has been used for selective removal of H2S in
2.1.4. Syngas cooling and particulate removal first stage and CO2 in second stage from the sour syngas, as presented in
The hot product gas from the gasifier is cooled using a syngas recycle Fig. 3, using dimethyl ether polyethylene glycol (DEPG) as a solvent.
quench and water quench to lower the temperature, below the ash Most of the H2S in the feed is absorbed in the semi-lean solvent coming
melting point. Syngas then goes through a syngas convective cooler, from CO2 absorber, as shown in Fig. 3. The H2S free gas from the top of
where the temperature of the syngas is lowered to a minimum of 230 ◦ C the H2S absorber is sent to the CO2 absorber. H2S and CO2 free syngas
(450◦ F). HP steam is also raised in this section to be used in the steam from the top of CO2 absorber is sent to power generation section and/or
cycle. The solid particles in the raw syngas, like fly ash are removed in ammonia and methane production after exchanging its cold energy with

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 4. Flow diagram of single effect LiBr-H2O ARS, Source: modified from Mussati et el., 2016 [49].

the incoming sour syngas to the H2S absorber. A split stream of the combustor as a diluent, as shown in Fig. 1, so that formation of thermal
loaded solvent (about 1/3) from the bottom of the CO2 absorber is NOx can be reduced by limiting lower heating value of syngas [45]. The
chilled, and sent to the H2S absorber. The H2S rich solvent from the injection of diluent N2 is adjusted based on the flow of syngas to the GT
bottom of the H2S absorber is heated by utilizing the heat of lean solvent both in IGCC 100% power and co-generation designs. In 100% power
leaving from the stripper (see Fig. 3). The heated solvent then enters in case the mole fraction of H2 in the mixture of syngas and diluent ni­
H2S concentrator, where N2 as a stripping agent is utilized at HP than trogen is 0.449. This is appropriate composition of H2 to limit the lower
H2S absorber pressure, so that compression of the recycled vapors to the heating value (LHV) of syngas before burning, keeping in view the
H2S absorber is not required. The solvent from the bottom of the H2S thermal constraints of the gas turbine. Same mole fraction of H2 in the
concentrator sent to the Selexol stripper for the removal of H2S from the mixture of syngas and diluent nitrogen (i.e., 0.449) is kept for each
solvent. The stripped solvent is sent to the top tray of the CO2 absorber as design. Furthermore, 10% of the total compressed air required for the
a lean solvent. The temperature of lean solvent is initially lowered to combustion of the syngas is used as coolant in GT both in 100% power
35 ◦ C from 46.04 ◦ C, using cooling water in cooler-2 and further lowered and co-generation designs. Turbine outlet temperature is also adjusted
to 10 ◦ C using chiller-2, as shown in Fig. 3. From CO2 absorber the to 566 ◦ C by controlling the volume of HP air fed to the combustor. The
remaining portion of the loaded solvent is heated and sent through a heat contained in exhaust gas leaving from the GT was recovered
series of flash vessels to recover CO2 for compression in preparation for through a HRSG (see Fig. 1). In this study, HRSG was configured by a
storage. triple-pressure steam generation unit with steam reheating arrange­
Vapors from the first flash vessel, generally called the H2 recovery ment, because it is proved to be highly efficient and cost-effective in
drum, which operates at about 20.7 bar pressure are recycled to CO2 several studies [43,44]. The power generated by steam turbine was
absorber in order to recover the dissolved H2 in the solvent [44]. After optimized by adjusting the flow of HP, intermediate pressure (IP) and LP
removing the absorbed H2, the CO2 rich solvent stream then goes water. The temperature of the exhaust gas leaving from the HRSG stack
through two additional flash vessels, medium pressure (MP), and LP, to is restricted to 143 ◦ C by controlling the flow rate of water entering in
release CO2. The semi-lean solvent leaving the LP flash vessel is chilled the economizer of the HRSG. The operating conditions of pressure and
before returning to the CO2 absorber. A propane vapor compression temperature for HP, IP and LP turbine have been presented in Table 1.
cycle is considered for refrigeration. Modeling of all columns in Selexol Preheating of the water to be used for steam generation is achieved
process have been performed considering equilibrium stage modeling through heat exchangers used in gasification and WGSR section. The
that may overestimate the extent of absorption [44]. For the calculation flowsheet of power block simulated in Aspen Plus® is presented in Ap­
of the auxiliary power consumption of the AGR using dual stage Selexol, pendix A.
power consumed by solvent pumps, recycle compressors and power
consumed by vapor compression cycle for chilling of the solvent is 2.1.8. Methane and ammonia production
considered [44]. The recovered CO2 has been compressed up to pressure Methane production is accomplished using two high temperature
of 153 bar to transfer to pipeline for storage purpose. The flowsheet of reactors in series [20], as shown in flowsheet simulated in Aspen Plus®
dual stage Selexol process simulated in Aspen Plus® is presented in and provided in Appendix A. The reacting streams of H2 and CO are pre-
Appendix A. heated up to 229 ◦ C before they react in first reactor. High temperature
of gases coming from first reactor is utilized in raising HP steam for
2.1.7. Combine cycle power generation power generation. The temperature of hot gases coming from first
The GT compressor supplies air to the GT combustion chamber and reactor is lowered to 299 ◦ C and a major portion is recycled back to first
to the GT blades. N2 produced in ASU is also injected into the GT reactor to enhance the methane conversion. The sensible heat of gases

8
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Table 4 effect. The refrigerant enters the evaporator, where the evaporation of
Identity description of different designs considered for thermodynamic and that refrigerant by the relatively hot water which requires chilling, takes
economic analysis. places. These evaporated saturated water vapors enter the absorber and
Design Description are absorbed in the weak solution to make strong solution. The pressure
Identity of the strong solution is increased using solution pump up to the pressure
Design-1 IGCC 100 % power without carbon capture level of the generator. Strong solution preheats in the SHE and it enters
Design-2 IGCC 100 % power with carbon capture the generator to continue the absorption chiller cycle.
Design-3 IGCC co-generation design with carbon capture
(Low methane, low ammonia production and high power
3. Methodology
generation)
Design-4 IGCC co-generation design with carbon capture
(High methane, low ammonia production and medium power Total five designs of IGCC systems (see Table 4) have been simulated
generation) using Aspen Plus® software. IGCC 100% power without carbon capture,
Design-5 IGCC co-generation design with carbon capture IGCC 100% power with carbon capture and three designs of IGCC co-
(Low methane, high ammonia production and medium power
generation)
generation have been considered. The schematics of these designs
Design-2A ARS integrated design-2 have been presented in Fig. 1 (a) and Fig. 2 (a). Dry feed technology
Design-3A ARS integrated design-3 using Shell gasifier is implemented on local Pakistani lignite coal to
Design-4A ARS integrated design-4 assess the actual status of the indigenous resources. The model param­
Design-5A ARS integrated design-5
eters of the simulation and design specifications are taken as per stan­
dards given in literature. Thermodynamic performance of all five
after second reactor is also utilized in raising IP steam. The methanation designs has been estimated and compared. The CO2 emissions from all
is hydrogenation of CO, and this reaction is highly exothermic in nature five designs are also assessed and compared. To reduce the CO2 emis­
[20], as presented by Eq. (2) [20]. sion, load of conventional chillers based on vapor compression has been
partially shifted to ARS, which is integrated with Selexol based AGR
CO + 3H2 ⇌CH 4 + H2 O(ΔH o = − 206kJ/mol) (2) process as shown in Figs. 1 (b) and 2 (b). Modeling of the ARS has been
Ammonia production occurs by the hydrogenation of nitrogen, as performed in MATLAB®. Validation of both IGCC designs and ARS was
shown in reaction Eq. (3) [20]. The H2 is received from the cleaned performed before thermodynamic and economic analysis. Based upon
syngas and the N2 from the ASU. The ammonia production takes place in the selling price of the electricity and co-products, like methane and
three reactors, as shown in flowsheet provided in Appendix A. The ammonia, the performance comparison of all designs for maximum
ammonia synthesis reaction takes place in temperature range of annualized revenue has been presented, with special emphasis on
427–507 ◦ C and pressure of 159 bar. The separation of converted reduction in GHGs to the environment. Complete economic analysis has
ammonia takes place at low temperature, which is accomplished using also been performed to assess the capital and operating expenditures of
conventional chillers. The specifications of ammonia and methane the IGCC designs. Capital and operating and maintenance cost of ARS is
production plants are provided in Table 1 and flowsheets simulated in also included in the ARS integrated IGCC systems to estimate the
Aspen Plus are presented in Appendix A. financial impact of ARS integration.

N2 + 3H2 ⇌2NH3 (ΔH o = − 46kJ/mol) (3) 3.1. Selection of coal

The methane and ammonia production processes have been vali­
dated against literature data [20]. The auxiliary consumption during In this study, low-quality Pakistani lignite was selected for the
ammonia production by compressors and refrigeration in this work is thermodynamic and economic feasibility studies of the indigenous re­
0.54 kW/kg (of ammonia), which is in close agreement with 0.51 kW/kg sources. The considered Pakistani coal represents the characteristics of
[20]. Similarly, the auxiliary consumption by methane compression and major existing Pakistani coal reserves [50]. The average moisture con­
recycle compressor in this work is 0.090 kW/kg (of methane), which is tent of the coal is 44.92% and ash content is 4.36% on as-received basis.
also comparable with 0.086 kW/kg [20]. The proximate and ultimate analysis of the coal is presented in Table 2,
along with HHV of the coal. The selected coal was initially tested for
gasification performance using Shell and General Electric (GE) gasifiers,
2.2. Process description of ARS as presented in previous work [51]. Cold gas efficiency (CGE) and ox­
ygen to coal ratio for the selected coal confirmed its suitability in this
A single effect ARS has been employed in this study (to avoid inte­ study.
gration complexities), which consists of an evaporator, absorber,
generator, condenser, solution heat exchanger (SHE), throttling valve, 3.2. Selection of gasifier
and a solution pump, as presented in Fig. 4. LiBr-H2O is employed as an
absorbent-refrigerant working pair in this work because of its high co­ Selection of proper gasification technology plays an important role
efficient of performance (COP) and high cooling capacity than H2O-NH3 on the overall performance of the IGCC power generation system. Dry
system [48]. All processes in single effect ARS take place at two different feed and slurry feed are two important feeding technologies for various
pressure levels. Addition of heat in generator to vaporize the refrigerant types of the gasifiers. In author’s previous study [51], simulation of the
and condensation of refrigerant takes place at HP, whereas evaporation entrained flow based gasification was performed for both dry feed and
and absorption takes place at LP. Strong solution of LiBr-H2O when slurry feed systems using three Pakistani coals. Based on the sensitivity
enters in the generator, water boils off and leaves the generator as su­ analysis performed for the CGE of the gasifier at varied O2 to coal ratio,
perheated vapors from the top, leaving behind the weak solution. Weak it was concluded that, the dry feed gasification using Shell gasifier is an
solution (with respect to refrigerant), after exchanging its heat with the appropriate option for the gasification of low quality Pakistani lignite
strong solution coming from the absorber in SHE, enters the LP absorber. coals. Therefore, dry feed gasifier using Shell technology based on 95%
This weak solution preheats the strong solution in SHE and pressure is pure O2 has been considered for this study.
reduced in throttle valve. On the other hand, superheated water vapors
leaving from the generator are condensed in the condenser by cooling 3.3. Simulation settings
water. After leaving the condenser, saturated liquid of refrigerant passes
through the expansion valve, where throttling process causes chilling The simulation models for the 100% power with carbon capture

9
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

(base case) and co-generation cases of the IGCC system have been the effective energy available in the exhaust gases can be calculated for
developed in Aspen Plus® V.11. The base case model of the IGCC plant is the evaluation of the heat load of the ARS. The heat transfer rate from
based on seven major units, which includes coal preparation unit, the exhaust gas to the generator of ARS is given by Eq. (4) [56].
gasification unit, ASU, WGSR, HRSG, AGR section, and combined cycle, ( )
Qexh = mexh hexh,in − hexh,out − Qins (4)
as presented in Fig. 1. The co-generation plant has two additional units
of methane and ammonia production, as shown in Fig. 2. The ARS to be In Eq. (4), mexh is the mass flow rate of exhaust gas, hexh,in is the
integrated in AGR for lean solvent chilling is simulated in MATLAB using specific enthalpy of the exhaust gas at the entrance of the generator and
best available correlations for phase equilibria and thermodynamic hexh,out is the specific enthalpy of exhaust gas at the exit of the generator.
properties [54]. Qins is the heat transfer from the exhaust gas to the environment through
The property method selected to model coal milling is SOLIDS. the insulated wall of the generator. The enthalpy of exhaust gas can be
Particle size distribution (PSD) of the coal is adjusted using two multiple calculated using Eq. (5), as follows [56].
role mills to achieve the desired particle size of 100 µm [8] for the 80%
of the feed. ∑
6
hexh, − hexh, = yi (hin − hout )i (5)
Gasification unit is simulated using RGibbs reactor model in Aspen
in out
i=1
Plus®, which utilizes Gibbs free energy minimization laws to generate
the reaction products [55]. Coal and ash are considered as non- where, yi, hin, and hout are the mass fraction, inlet enthalpy (kJ/kg) and
conventional components by Aspen Plus®. To calculate the enthalpy outlet enthalpy (kJ/kg) of the constituent elements of the exhaust gas. In
and density of coal and ash, the HCOALGEN and DCOALIGT models this study, CO, CO2, H2O, O2, Ar and N2 gases have been considered as
have been chosen, respectively in Aspen Plus®. Therefore, gasification exhaust gas components. The exhaust gas components concentration
process can be modeled by converting non-conventional coal into con­ was taken from the Aspen Plus® simulation model, developed for coal
ventional components, like H2O, C, O2, N2, S, H2, Cl2 and Ash, using the based IGCC plant, while the enthalpy was calculated by CoolProp inte­
RYield model. The mass yields of these components is calculated using grated in MATLAB by CoolPropMATLAB_wrap. Enthalpy of exhaust gas
calculator block based on the ultimate analysis of the coal [47]. From components calculated by CoolProp was also confirmed by REFPROP on
above discussion, it is clear that to model gasification in IGCC process same conditions of temperature of the exhaust gas.
both RYield and RGibbs reactor work in integrated form in Aspen Plus®
[47]. The carbon conversion is set to 99.5% in RGibbs reactor, in line 3.4. Base case simulation
with the literature for the same type of coal and gasifier [8]. The
composition of syngas from entrained flow slagging gasifiers is close to The thermal input to the plant is 1585.713 MWt (based on HHV),
equilibrium for most of the gasification homogeneous reactions. The equivalent to coal feed rate of 412.5 tons/h. The net plant efficiency of
WGS reaction is some time not at equilibrium at the gasifier tempera­ the base case is 32.33% (based on HHV), which is in good agreement
ture. A specific temperature at which the reaction equilibrium is satis­ with results reported in National Energy Technology Laboratory (NETL)
fied is required to be predicted [47]. The composition of syngas at the for low quality North Dakota lignite [8].
exit of the gasifier is compared with literature [8] to evaluate the reli­ The compressors and blower of WTA consume a significant amount
ability of the simulated model. Property method used in gasification is of power, 17.69 MWe is consumed in order to dry the coal from initially
Peng-Robinson equation of state with the Boston Mathias alpha function 44.92 wt-% to 12 wt-%, the details of modeling and simulation of WTA
(PR-BM). on Pakistani lignite can be found in authors previous work [35]. The
To model most of the processes of the complex IGCC system, such as dried coal is converted to syngas at a CGE of 82.9% (based on HHV)
ASU, syngas cooling, WGSR, GT, and flue gas in the HRSG, the property using Shell gasifier. The syngas leaves the gasifier at a temperature of
method used is PR-BM. This method could accurately calculate ther­ 1364.9 ◦ C and pressure of 42.4 bar. The hot raw syngas is cooled to
modynamic properties for a nonpolar or mildly polar mixture such as 369.9 ◦ C by cooled syngas recycle and water quench [8], followed by
CO2, H2S, and H2. The STEAM-TA (Steam table correlations) is used to bulk particulate removal via cyclone and filter. After removing partic­
model the boiler feed water, heaters, steam boilers, and unit operations ulate using filters, the temperature of gas is lowered to 232 ◦ C, while
of steam turbine along with exchangers in HRSG. To model carbon raising HP and IP steam. Further removal of fine particulates as well as
capture by physical absorption, the Selexol process has been simulated water soluble contaminants, such as chlorides ensured by scrubbing the
using the perturbed-chain statistical associating fluid theory (PC-SAFT) gas with grey water. In WGSR the IP steam is injected to maintain H2O to
property method by considering DEPG mixture as a single component. CO ratio of 1.8 on molar basis [57]. This ratio is sufficient for the con­
Modeling of ammonia production in co-generation has been executed version of CO and carbon deposition prevention on the catalyst [8]. The
using Benedict-Webb-Rubin-Starling (BWRS) and Redlich-Kwong-Soave temperature of the syngas rises up to 458.2 ◦ C in first stage WGSR, while
with Boston-Mathias (RKS-BM), as property method. Peng-Robinson shifting the bulk of the CO contained in the syngas to CO2. The exit
(PR) property method is used in methane production process simulation. temperature is sufficient to raise HP and IP steam along with heating of
PLOX cycle for air separation has been considered in this study and the quench water at later stages. Second stage WGSR operated at lower
simulated in Aspen Plus®. Requirement of O2 is same in all cases of the temperature to enhance CO shifting. The temperature at the exit of the
IGCC system because of no change in gasification process. Power second WGSR is 257 ◦ C, which is utilized for the preheating of the boiler
required for N2 compressor is calculated based on the flow of N2 feed water (BFW) of the power block. Before H2S and CO2 removal in
required in co-generation designs. Selexol process the syngas is passed through coolers and knock out
The ultimate and proximate analysis, required for the HCOALGEN drums. In two stage WGSRs, about 97.3% of the initial CO is converted
and DCOALIGT model in Aspen Plus® are presented in Table 2 for to CO2. Thereafter, the syngas is cooled to 35 ◦ C before it enters the
Pakistani lignite coal [52]. Design and operational parameters used in Selexol CO2 capture process.
the modeling of the IGCC system are provided in Table 1. The developed The separated CO2 stream is compressed to 153 bar for the under­
model is calibrated for low rank coal and Shell gasifier [8], to ensure the ground transportation and storage [8]. Up to 34.34 MWe power is
reliability of the simulated model. The compositions of the syngas at consumed by CO2 compressors and pumps, but, in order to minimize the
different locations of the IGCC plant are compared with the literature [8] compression work, intercooling is performed [40]. Carbon capture of
and presented in Section 4.1. 92% and H2S capture of 99.98% is achieved in this study. Water balance
The modeling strategy for ARS integration include flue gas enthalpy includes water demand in quench wash, slag handling, condenser
evaluation and heat transfer to the ARS generator. Since the mass flow makeup and cooling tower makeup. Water received from water drying
rate and the exhaust temperature are known from Aspen Plus® model, and condensate from syngas considered as internal recycle to offset the

10
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

water demand. The difference between water demand and internal [40]. Transport, storage and monitoring (TS&M) costs for CO2 seques­
recycle is raw water withdrawal from the ground. Water consumption is tration are not included in the cost analysis. Elemental Sulphur pro­
the net impact of the process on the water source, which is the difference duction using Claus process is not considered for both 100% power
of raw water demand and process water discharge (i.e., cooling tower generation and co-generation designs. The overall initial catalyst fill (in
blowdown) [20]. The cooling tower makeup represents the largest ft3) has been estimated from NETL reports [8,20] through a linear
consumer of water, evaluated as per guidelines provided in literature interpolation between catalyst volume and production rate [59]. The
[8]. The water consumption of the base case is 11.64 m3/min. Water cost of water, and makeup and waste water treatment chemicals have
consumption and withdrawal of base case, as well as, other designs is been evaluated based on the requirement of water and chemicals for
presented in section 4. Steam consumption for the Selexol stripper and specific size of the plant.
for the heating of the syngas after Selexol is extracted from the HRSG The O&M costs are evaluated as per the available guidelines [45] to
and WGSR section. The performance summary of base case along with update the expenses at $2011 rates. Specifications for the expenses
other designs of the IGCC system has been presented in section 4. The associated with the daily operation of the power plant, including oper­
flow sheet showing all process units of the base case is presented in Fig. 1 ating labor, maintenance material and labor, administrative and support
(a). labor, consumables, and waste disposal etc. have been taken from
literature [45]. The O&M costs include fixed and variable costs. Fixed
costs are comprised of different types of labor i.e., annual operating
3.5. Economic evaluation
labor, administrative and support labor, and maintenance labor, in
addition to property tax and insurance etc. The workers are assumed to
This section covers the strategy employed to perform economic
be paid an average salary of 39.70 $/h [45]. The burden of operating
evaluation of IGCC 100% power and co-generation designs. Strategy for
labor is assumed at 30% of the base labor rate. Labor administrative and
economic evaluation of ARS integrated with IGCC 100% power and co-
support are assessed at 25% of burdened O&M labor. Property tax and
generation designs is also presented in this section.
insurance costs of fixed O&M costs are estimated at 2% of the TPC [8].
Variable O&M costs are determined based on the availability of plant,
3.5.1. IGCC 100% power system and Co-generation designs
which include maintenance cost and cost of consumables, like coal,
The scaling methodology is employed to estimate capital costs for the
water, catalysts and sorbents etc. Initial fill of catalysts and sorbents is
specific type of an IGCC design according to guidelines provided in NETL
also considered in the cost analysis. Costs associated with the waste
report [58]. Single stage dry feed gasifier (i.e., Shell gasifier) operated
disposal after reaching their end of life are also considered. Reference
for O2 blown low-quality coal with CO2 capture, meets the category
costs of water, waste water treatment chemicals, shift catalyst, Selexol
matrix 6 for economic evaluation [58]. The costs of plant of interest can
solution, methane and ammonia catalysts have been taken from litera­
be evaluated by scaling from a quote for a similar plant configuration by
ture [45]. Total overnight capital (TOC) is used to calculate COE or total
using Eq. (6) [40]. Different process parameters obtained from simula­
annualized expenditures (TAEs). TOC is the initial investment cost,
tion, like, coal feed rate or oxidant feed rate, etc. have been employed
which includes pre-production costs, inventory capital, land costs,
along with an exponent in this equation [40]. The exponent is to account
financing costs and other owner’s costs at the rate, as presented in
for economies of large-scale equipment for additional capacity addition.
section 4. Pre-production costs have been evaluated by adding six
NETL quality guidelines report [58] comprises a listing of frequently
months fixed O&M costs, one month variable O&M cost, 25% of one
used pieces of equipment and their corresponding scaling exponent for
month coal cost at 100% CF and 2% TPC [9]. Inventory capital is the 60
various plant types, along with their ranges of applicability. The same
day supply of consumables at 100% CF and cost of spare parts, which is
document [58] also guided about the NETL report from where, reference
0.5% of TPC [9]. Financing costs is the 2.7% of TPC and other owner’s
parameters and reference costs have to be selected for specific account
costs is evaluated at 15% of TPC. To account for the inflation, the capital
number during total plant cost and other costs evaluations (details can
cost escalation during expenditure period is assumed to be 3.6% and the
be found in supporting material). For comparison purpose, 2007 cost
total capital expenditure during the 5-year construction period is
data of Shell gasifier based on lignite coal with carbon capture [8] has
distributed at 10%, 30%, 25%, 20% and 15% each year [60]. 100% of
been used for power generation (base case) during the scaling devel­
the TOC is depreciated over the life of the IGCC plant. The O&M costs as
opment of the plant.
well as coal costs are assumed to have an annual inflation rate of 3.0%
After comparison of the costs of this work and [8] for the same
[60].
conditions, the total plant costs of the power generation (base case) and
The financing structure has been approximated with a capital charge
co-generation cases have been updated to base year (2011) by ac­
factor (CCF) of 0.1243 [8] for both 100% power and co-generation de­
counting the price fluctuations reported in [40], to consider increase in
signs. The CCF is evaluated by assuming capital expenditure period of 5
costs of equipment in the next years. The costs of consumables, like
years for the IGCC plant. Considering coal based IGCC plant with carbon
water, solvents and catalysts for the calculation of operating and
capture, a high risk plant, an equity of 55% is required [8]. The price per
maintenance (O&M) costs have been updated from literature [45]. The
ton of Pakistani lignite is assumed as $30 [50]. The COE and levelized
total plant cost (TPC) includes cost of process equipment, cost of ma­
cost of electricity (LCOE) in first operating year (i.e. 2016) have been
terial, direct labor cost, engineering services and project contingencies.
considered performance indicators for the 100% power generation
( )Exp ( )0.9
SP TS plant, and have been approximated using Eq. (7) [8] and Eq. (8) [60],
SC = RC × ×(1 + a)Scl × (6) respectively. The first operating year LCOE is evaluated by multiplying
RP TR
first operating year COE with a levelization factor (LF) [60]. The LF is
where, SC is scaled cost (i.e., TPC) of equipment or section of the IGCC evaluated at 12% internal rate of return on equity and an annual 3%
plant, RC is reference cost, SP represents the scaled parameter, RP is the general inflation rate over the 5 years of capital expenditure for coal
reference parameter, like flow or capacity etc. considered to scale the based power plants. The operational period of plant is assumed as 30
equipment. a is the annual escalation rate, Exp is the scaling exponent years for economic analysis [60].
which accounts for the large size of the equipment, Scl is difference of ( $ ) (CCF × TOC) + OC + (CF × OC )
year to which you want to scale the cost and the current year. TS and TR (7)
Fix Var
COE =
MWh (CF × MWh)
are the number of equipment trains in the scaled plant and in the
reference plant, respectively. The exponent 0.9 is to benefit for the cost ( $ )
savings, when more than one identical train has to install. In this study, LCOE = COE × LF (8)
MWh
the number of trains of equipment are assumed same from a similar case

11
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Table 5
Production and market price scenarios of IGCC 100% power and co-generation system.
Production Scenarios of IGCC 100% power and Co-generation designs Market Price Scenarios of IGCC 100% power and Co-generation designs

IGCC Designs Production Scenarios Value Syngas Flow Market Scenarios Price of Product Value [29]

Design-2 100% Power, kWe,net 512,615 100% Avg. markets Methane, $/kg 0.60
Design-3 Low Methane, kg/h 10,292 9.12% Ammonia, $/kg 0.30
Low Ammonia, kg/h 5,895 4.71% Electricity, $/kW h 0.08
High Electricity, kWe,net 402,870 86.17% Low markets Methane, $/kg 0.50
Design-4 High Methane, kg/h 42,243 44.60% Ammonia, $/kg 0.20
Low Ammonia, kg/h 5,270 5.00% Electricity, $/kW h 0.06
Medium Electricity, kWe,net 177,280 50.40% High markets Methane, $/kg 0.70
Design-5 Low Methane, kg/h 5,289 4.60% Ammonia, $/kg 0.40
High Ammonia, kg/h 58,318 45.40% Electricity, $/kW h 0.10
Medium Electricity, kWe,net 184,312 50.00%

In Eq. (7), COE is the cost of electricity in the first operating year, CCF where, 4.75 is constant which accounts direct, indirect and other outlays
is the capital charge factor, TOC is the total overnight capital in first costs [61]. The PEC of each component involved in the system is
operating year, OCFix fixed annual operating cost evaluated in first calculated by detailed economic analysis; however, in this study, the
operating year, OCVar variable annual operating cost in first year of PEC is evaluated by the cost functions given in Table 3, for five com­
operation, CF is the capacity factor of the plant, assumed 80% for this ponents involved in single effect ARS. The cost of the component in the
study [8], and MW h is the annual net-megawatt hours generated at system available in any original year is converted to the scaling year
100% CF. In Eq. (8), LCOE is levelized cost of electricity and LF is the (2011) by employing the Chemical Engineering Plant Cost Index
levelization factor. The evaluation of the first year cost of production (CEPCI) as by Eq. (16). In all five components heat transfer is involved
(FYCOP) of fuel/chemical or cost of electricity (COE) generation is easy, which is direct function of HTA, calculated by U and the LMTD, as by Eq.
when one major commodity is being obtained from that plant. In co- (17).
generation designs because of multiple products, instead of evaluation ( )
of cost of plant with respect to one commodity, total annualized ex­ CEPCI scaling year
PECscaling year = PECreference year × (16)
penditures (TAEs) have been evaluated by considering first year capital CEPCI reference year
charge of the IGCC plant. The assumed CCF governs the finance struc­
Agen , Aab , Acond , Aevp and ASHE in Table 3 are HTAs of generator,
ture for plant life and capital expenditure period. For comparison pur­
absorber, condenser, evaporator and SHE, respectively.
pose, the annualized expenditures ($, Million) for 100% power with and
without carbon capture cases have also been evaluated. The TAEs have Qj
Aj = (17)
been calculated by Eq. (9). The total annualized revenue (TAR) in ($, Uj ×LMTDj
Million) from the different designs of the IGCC system has been evalu­
In Eq. (17), Uj is the overall heat transfer coefficient for component j.
ated by Eq. (10) derived from [20], by selling electricity, methane and
The values of U for different components of ARS are assumed to be
ammonia in one year.
constant for the given range of operating conditions and are available in
TAEs($, Million) = (CCF × TOC) + OCFix + (CF × OCVar ) (9) literature [65,65]. Qj is heat capacity for j component and calculated
from thermodynamic model. LMTDj for j component is given by Eq. (18).
TAR($, Million) = Revenueelectricity + Revenueammonia + Revenuemethane (10)
ΔTjH
Where, LMTDj = (ΔTjHot − ΔTjCold )/ln (18)
ΔTjC
Revenueelectricity = (CF × Yearly Net kWh × $/kWh)elecricity (11)
where, ΔTjHot and ΔTjCold are temperature difference between hot and
Revenueammonia = (CF × Yearly kg × $/kg)ammonia (12) cold ends, respectively.
For the operating cost analysis, the flows of utilities like, cooling
Revenuemethane = (CF × Yearly kg × $/kg)methane (13) water for absorber and condenser, and LiBr salt solution are evaluated
from the simulation model. The cost of LiBr salt solution is assumed as 4
Additional cost of carbon capture are expressed by CO2 avoided cost,
$/kg [66]. The details of financial structure such as project lifetime and
calculated by Eq. (14)[40].
interest rate are assumed taking into consideration the life of IGCC plant
COEwith cc − COEwithout cc and its financial structure.
CO2 Avoided Cost = (14)
CO2 Emissionwithout cc − CO2 Emissionwith cc

3.5.2. Absorption refrigeration system 3.6. Identity description of different designs of IGCC system
The procedure for economic analysis of ARS includes the calculation
of heat transfer area (HTA) of the main components of ARS, e.g., Identity description along with brief process configuration used in
generator, absorber, condenser, evaporator and solution heat exchanger different designs of the IGCC systems considered in this study for ther­
(SHE). Estimation of HTA requires, the evaluation of mass and energy modynamic and economic analysis have been presented in this section.
balance, log mean temperature difference (LMTD), and overall heat Design-1: This is 100% power design without carbon capture
transfer coefficient (U) is assumed based on the properties and condi­ considered for the evaluation of CO2 avoided cost based on the similar
tions of the flowing streams. The total capital investment (TCI) of the IGCC plant with no carbon capture. In this design, all of the syngas is
considered single effect ARS has been calculated from the purchased utilized in power generation and no pre-combustion carbon capture is
equipment cost (PEC) of j (five) main components involved in the considered. Shifting of the syngas after gasification is not considered as
considered single effect ARS, using Eq. (15) [61]. the carbon capture is not intended, so after retiring H2S from the syngas,
∑ it is sent to the power block. Design-2: In this design, up-stream and
TCI = 4.75 × PECj (15) downstream sections of the IGCC power plant are same, as of design-1.
After gasification, WGSR is installed which uses IP steam. After CO2

12
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

capture the syngas is introduced into power generation block, where Table 6
electricity generation is similar as discussed in design-1. Design-3: This is Comparison of the developed model with NETL 2011 [8] for low ranked coal.
an IGCC co-generation design with carbon capture. In this case, the up- Description NETL This Absolute Diff.
stream section is same like design-1 and design-2, but after syngas 2011 Work (%)
cooling using heat exchangers and hydrolysis reaction a specific amount -Composition of raw syngas after gasifier
(4.88%) of syngas is diverted to methanation section. The remaining (Mole fraction)
syngas after shifting is introduced into Selexol process. After syngas Nitrogen (N2) 0.0658 0.0668 1.52
cleaning, the syngas rich in H2 is diverted to methanation section and to Argon (Ar) 0.0100 0.0090 10.0
Methane (CH4) 0.0000 0.0000
ammonia section. The required N2 for ammonia production is main­
–
Carbon Monoxide (CO) 0.5271 0.5352 1.53
tained from ASU. The remaining syngas from Selexol is sent to power Hydrogen (H2) 0.2477 0.2426 2.05
block. The percent flow of syngas used for the production of methane Carbon dioxide (CO2) 0.0643 0.0571 11.19
and ammonia, and for power generation is presented in Table 5. Design- Water (H2O) 0.0802 0.0857 6.85
Hydrogen Sulphide (H2S) 0.0032 0.0031 3.12
4: In this co-generation design, high quantity of methane production is
Ammonia (NH3) 0.0014 0.0001 –
considered along with low ammonia and medium power generation.
Design-5: This design produces higher amounts of ammonia along with -Composition at the outlet of the WGSR
(Mole fraction)
low methane, and medium power generation. Carbon capture and its
Nitrogen (N2) 0.0459 0.0465 1.52
compression is also considered in all co-generation designs. The percent Argon (Ar) 0.0070 0.0063 10.0
flow of syngas in all co-generation designs is presented in Table 5 and Methane (CH4) 0.0000 0.0000 –
Fig. 2 (a). Carbon Monoxide (CO) 0.0101 0.0101 0.00
Hydrogen (H2) 0.5302 0.5317 0.28
IGCC – ARS integrated designs (Design-2A, Design-3A, Design-4A and
Carbon dioxide (CO2) 0.4026 0.4024 0.05
Design-5A): ARSs powered by hot water obtained from waste or low Water (H2O) 0.0017 0.0017 0.00
quality heat from the IGCC system and flue gas have been integrated Ammonia (NH3) 0.0000 0.0000 –
with chillers of Selexol process in design-2, design-3, design-4 and
-Thermodynamic performance
design-5. These IGCC designs integrated with ARS have been designated comparison
as design-2A, design-3A, design-4A and design-5A, respectively, as Gas Turbine Power, kWe‘ 456,600 456,110 0.11
shown in Figs. 1 (b) and 2 (b). Steam Turbine Power, kWe 256,700 248,870 3.05
In case of co-generation designs, energy conversion efficiency is Total gross power, kWe 713,300 704,980 1.17
Total auxiliaries, kWe 213,240 217,403 2.20
calculated by dividing HHV of products with thermal input to the system Net Electrical Efficiency, % (HHV) 31.7 30.9 2.50
i.e., (HHVmethane + HHVammonia)/HHVcoal [67]. For the co-generation CO2 Emissions, tons/year 423,890 433,450 2.25
designs, at least half of the heat value in coal is transferred to elec­
tricity generation block and net electricity efficiency is evaluated, like
(net electricity/HHVcoal) [67]. The thermodynamic performance of the systems for various scenarios, based on the production scale have been
ARS integrated IGCC designs is calculated by subtracting the thermal performed. Instead of varying the flow of syngas in minor percentages to
power produced by ARS in the form of cooling energy from the cooling generate number of scenarios, as in previous work [29], three scenarios
load caused by Selexol chillers. have been developed in this work, which covers varied quantities of
methane, ammonia and electricity generation. The production scenarios
have been described in Table 5.
3.7. Scenario generation In this study, total selling revenue obtained by selling all outputs of
the plant is calculated based on the average market prices of these
Consideration of various scenarios for the production decision make products (see Table 5). Construction and first year operational cost of
IGCC co-generation system very complex. Economic evaluation of the particular scenario is calculated by taking into account the TOC, fixed
most suitable or best scenario is a haunting task, but if one scenario and variable O&M costs. As the operating decisions are flexible, the
performs competitively at specific market, it is very important to eval­ decision corresponding to the maximum net revenue will be the optimal
uate its economic feasibility. Therefore, this study incorporates all the decision among the three scenarios for the given average market prices.
important parameters and their ranges to perform economic analysis These production decisions strongly depend on the market behavior
based on the calculation of TOC, variable O&M cost and fixed O&M cost. with respect to the selling prices (or demand of product) of the indi­
The feasibility of any scenario is assessed based on the revenue received vidual products. In co-generation designs the portion of electricity is
by selling all the outputs from the IGCC co-generation system. For this medium to high because of generally high demand of the electricity in
purpose, various scenarios for production decisions in different markets all types of markets. But, if there is less demand of electricity in the
are given in the following sub-sections. market, then the management can go for chemical (i.e., ammonia) or
fuel (i.e., methane) production. In context to Pakistan, during Covid-19
3.7.1. Scenarios for production decisions the general industry was partially closed, so less consumption of elec­
Selling prices of methane, ammonia and electricity may vary in tricity was observed. In situations, when plant is switched to ammonia
future. The selling prices of ammonia and methane in different regions (to fulfill agriculture requirements) or to methane production (to meet
may also disturb the supply chain of these commodities. The un- domestic demands), the evaluation of revenue to expenditure ratio be­
predictability in prices as well as in demand will compel the plant comes important. Therefore, the effect of market un-certainty in the
management to change the decision regarding co-generation. The pro­ product selling price is discussed in the next section. It should be noted
duction quantity of these products (methane, ammonia and electricity) that special focus is paid on the effect of change in capital cost by
also depends on the market prices and demand. The decision regarding considering these production scenarios. It should also be noted that,
the production of a specific product may be made by changing the flow 80% capacity factor is assumed for IGCC 100% power and co-generation
of syngas for the production of methane, ammonia and electricity, as designs.
shown in Fig. 2. Complete economic analysis of IGCC co-generation

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Table 7
Comparison of the developed ARS model with Mussati et al., 2016 [49].
Parameters Heat load, Q (kW) Heat transfer area, (m2) LMTD, (◦ C)

Process Unit This work Mussati, 2016 [49] This work Mussati, 2016 [49] This work Mussati, 2016 [49]

Generator 69.511 69.763 3.196 3.247 14.500 14.322

Absorber 66.266 66.543 5.820 5.769 16.265 16.477
Condenser 53.256 53.220 2.597 2.585 25.598b/8.199c 25.148b/8.001c
Evaporator 50.00a 50.00a 3.809 3.803 8.749 8.764
SHE 12.484 12.245 0.610 0.594 20.436 20.602
Total – – 16.03 16.00 – –
a
Fixed evaporator capacity.
b
Sensible heat.
c
Condensation heat.

Table 8
Performance summary of various designs of IGCC system.
100% power without CC 100% power with CC Co-generation with CC

Power generation summary Design-1 Design-2 (Base Case) Design-3 Design-4 Design-5

Gas Turbine Power (kWe) 473,810 462,480 376,690 185,230 223,600

Steam Turbine Power (kWe) 360,890 267,590 233,238 167,131 177,744
Total Power, (kWe) 834,700 730,070 609,928 352,361 401,344
Auxiliary Power Summary (kWe)
Coal Milling 3,045 3,045 3,045 3,045 3,045
Coal Drying 17,693 17,693 17,693 17,693 17,693
ASU Main Air Compressor 48,232 48,232 48,232 48,232 48,232
Oxygen Compressor 12,724 12,724 12,724 12,724 12,724
Nitrogen Compressors 69,095 63,972 54,224 31,193 36,801
ASU Auxiliary Powera 1,000 1,000 1,000 1,000 1,000
Methane Compression – – 480 1,971 247
Methane Recycle Compressor – – 448 1,840 231
Ammonia Refrigeration – – 1,135 1,015 11,230
Nitrogen Compression for Ammonia – – 587 525 5,804
Hydrogen Compression for Ammonia – – 1,389 1,241 13,737
Ammonia Recycle Compressor – – 98 88 971
CO2 Compressor – 34,342 32,592 27,442 33,442
Boiler Feedwater Pumps 3,536 2,607 2,109 1,028 1,417
Condensate Pump 352 326 270 167 203
Syngas Recycle Compressor 796 815 815 828 828
Acid Gas Removal – 21,639 20,464 17,271 21,042
Gas Turbine Auxiliariesa 1,000 1,000 1,000 1,000 1,000
Steam Turbine Fixed Load Auxiliariesa 100 100 100 100 100
Miscellaneous Balance of Planta 3,000 3,000 3,000 3,000 3,000
Circulating Water Pump – 2,667 2,046 1,445 1,706
Cooling Tower Fans – 1,470 1,248 870 1,026
Transformer Losses 2,897 2,825 2,360 1,363 1,553
Total Auxiliaries, (kWe) 163,470 217,455 207,058 175,081 217,032
Net Power, (kWe) 671,230 512,615 402,870 177,280 184,312
Net Electrical Efficiency, % (HHV) 42.33 32.33 25.41 11.18 11.62
Methane Productb (kg/h) – – 10,292 42,243 5,289
Ammonia Productc (kg/h) – – 5,895 5,270 58,318
Energy Conversion Efficiencyd (%) – – 36.86 48.58 39.07
Cold Gas Efficiency, % (HHV) 82.9 82.9 82.9 82.9 82.9
Condenser Cooling Duty, (GJ/h) 2,098 1,612 1,418 1,015 1,183
As-Received Coal Feed,(kg/h) 374,214 374,214 374,214 374,214 374,214
Thermal Input, (kWt) 1,585,713 1,585,713 1,585,713 1,585,713 1,585,713
Annual CO2 Emission, (tons/year)net 3,954,420 426,665 383,782 314,069 225,706
Annual CO2 Emission from AGR Chillerse, (tons/year)net – 28,824 27,294 23,024 28,054
Specific CO2 Emission (kg/MW hnet) 762.0 107.7 – – –
Raw Water Withdrawal (m3/min) – 15.10 13.63 10.81 11.80
Raw Water Consumption (m3/min) – 11.64 10.57 8.56 9.19
a
Auxiliaries assumed from NETL report based on same type of IGCC plant [57].
b
Methane product is 90% pure (vol. basis).
c
Ammonia product is 98.5% pure (vol. basis).
d
Overall energy conversion efficiency of the IGCC co-generation system is calculated by dividing energy of product with energy input i.e. (Power + Ammonia +
Methane) /HHVcoal [67].
e
Presented to show the CO2 emission impact from chillers, if auxiliary electricity for chillers has to be purchased from the outside market.

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Table 9 Selling prices of methane, ammonia and electricity in fluctuated markets

Performance improvement after ARS integration with various designs of the are listed in Table 5 [29].
IGCC system.
Power generation summary Design- Design- Design- Design- 4. Results and discussions
after ARS integration 2A 3A 4A 5A

Total Power, (kWe) 730,070 609,928 352,361 401,344 Before thermodynamic and economic analysis of various designs of
Power Consumption by ARS 16,765 15,491 13,881 16,809 IGCC 100% power and co-generation system, validation of thermody­
integrated AGR, (kWe) namic model is also performed to ensure the reliability of the predicted
Total auxiliariesa, (kWe) 212,968 202,457 172,418 213,212
results. A detailed thermodynamic and economic analysis of all designs
Net Power, (kWe) 517,102 407,471 179,943 188,132
Net Electrical Efficiency, % 32.61 25.70 11.35 11.86 of IGCC 100% power and co-generation, and ARS integrated designs
(HHV) have been presented in this section.
Reduction in CO2 Emission due 13,071 13,336 9,090 11,352
to ARS, (tons/year)net 4.1. Validation of IGCC model
Specific CO2 Emission (kg/MW 106.7 – – –
hnet)
Raw Water Withdrawal (m3/ 16.39 14.89 11.43 13.06 The Aspen Plus® model used in this study for the thermodynamic
min) analysis is validated with the only authentic report [8] published on low
Raw Water Consumption (m3/ 12.62 11.52 8.93 10.13 ranked coals. The composition of syngas predicted by Aspen Plus®
min)
model in this study after gasification and WGSR was compared with
a
Except AGR auxiliary, total auxiliary is same as in IGCC system without ARS literature [8], which found in close agreement as seen in Table 6. Results
integration (see Table 8). related to thermodynamic analysis and environmental emission were
also in close agreement, based on the same operating parameters and
3.7.2. Scenarios for market prices considering the same power consuming components. The details of the
Three types of markets have been studied for the previously dis­ previous work of the authors can be found from literature [68].
cussed IGCC designs (see Table 5). Average markets are taken to
consider Pakistan’s general perspective [29]. Average, low and high 4.2. Validation of absorption refrigeration system
market prices for all outputs from the three production based scenarios
have been assumed as shown in Table 5. Economic analysis for the ARS has been utilized to provide cooling to the lean solvent in
plant’s capital and O&M costs are already available in production sce­ Selexol process of the AGR section in IGCC plant. The thermodynamic
narios, hence further feasibility studies of IGCC co-generation designs performance of the developed ARS model is compared with literature
based on fluctuated markets help decision makers for the investment. [49], which found in close agreement, as can be seen in Table 7. Vali­
dation of both models considered in this study ensures that the predicted
results from the simulation are reliable.
Table 10
Energy Balance of IGCC 100% and co-generation designs with carbon capture.
4.3. Base case
Components of Heat Balance Design-2 Design-3 Design-4 Design-5

Heat In, GJ/h The IGCC base case, described in section 3.4, generates a gross power
Coal 5,709 5,709 5,709 5,709
of 730.07 MW out of which 462.48 MW (63.35%) is generated by GT
Auxiliary Power 783 745 630 781
Total 6,492 6,454 6,339 6,490
and 267.59 MW (36.65%) by steam turbine. The net electrical efficiency
of the base case (design-2) is 32.33% HHV. Two GTs of capacity 232 MW
Heat Out, GJ/h
have been considered for base case. The GT has the largest single item
ASU or ASU/Ammonia 341 315 269 332
Intercoolers cost of the plant, the rest of the plant is tuned and scaled to operate GTs
CO2 Compressors Intercoolers 212 201 169 206 at maximum power output in base case. The detailed performance
Condenser 1,612 1,418 1,015 1,183 analysis of the base case is presented in Table 8 along with other IGCC
HRSG Flue Gas 1,105 902 444 534 designs.
Methane – 514 1,986 272
Ammonia – 133 119 1,295
Auxiliary Cooling Load 294 302 391 426 4.4. Thermodynamics analysis
Process Losses 300 473 676 797
Power 2,628 2,196 1,269 1,445 Thermodynamic performance of IGCC 100% power without carbon
Total 6,492 6,454 6,339 6,490
capture (Design-1), IGCC 100% power with carbon capture (Design-2),
Design- Design- Design- Design- IGCC co-generation (Design-3, Design-4 and Design-5), ARS integrated
2A 3A 4A 5A IGCC 100% power (Design-2A) and ARS integrated IGCC co-generation
Heat In, GJ/h (Design-3A, Design-4A and Design-5A) are presented in Tables 8 and 9.
Coal 5,709 5,709 5,709 5,709 The front end of all designs, up to hydrolysis of the cooled syngas is
Auxiliary Power 767 729 621 768
same, and CGE of the gasifier based on the HHV is 82.9% in all cases. The
Total 6,476 6,438 6,330 6,477
quantity of coal used is also kept constant to make a realistic comparison
Heat Out, GJ/h for all cases. Other similarities include, more than 97% CO conversion in
ASU or ASU/Ammonia 325 289 252 305
Intercoolers
WGSR, 99.98% sulfur removal from the syngas, and 92% carbon capture
CO2 Compressors Intercoolers 212 201 169 206 in the dual stage Selexol process. The variables of the IGCC co-
Condenser 1,612 1,418 1,015 1,183 generation designs are the total power generation, total fuel
HRSG Flue Gas 1,057 864 425 514 (methane) and chemical (ammonia) production, gross and net CO2
ARS 64 65 44 56
emission, and auxiliary power consumption based on the varied load in
Methane – 514 1,986 272
Ammonia – 133 119 1,295 different designs.
Auxiliary Cooling Load 280 285 382 412 For the variable production of methane and ammonia in design-3, 4
Process Losses 298 473 668 789 and 5, the electricity generation is affected largely. In design-3, split of
Power 2,628 2,145 1,269 1,445 syngas towards methane production, and diversion of H2 rich syngas
Total 6,476 6,438 6,330 6,477
after cleaning toward ammonia production causes a reduction in

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Table 11
Summary of capital, operating and maintenance costs for all IGCC designs.
Cost Summary Design-1 Design-2 Design-3 Design-4 Design-5 Design- Design- Design- Design-
2A 3A 4A 5A

Fixed Operating (Opt.) Costs (First Opt. Year), 77,014 84,602 86,562 84,937 91,745 84,741 86,690 85,037 92,056
$×1000
Annual Variable Operating Costs including Fuel 145,585 150,344 150,590 150,333 150,629 150,863 150,793 150,467 150,831
(First Opt. Year), $×1000
Owner’s Costs, $×1000
-Preproduction Costs
6 Months Fixed O&M 15,220 15,919 15,919 15,919 15,919 15,919 15,919 15,919 15,919
1 Month Variable O&M 4,048 4,475 4,498 4,474 4,501 4,522 4,516 4,486 4,519
25% of 1 Months Fuel Cost at 100% CF 2,258 2,258 2,258 2,258 2,258 2,258 2,258 2,258 2,258
2% of TPC 35,994 41,142 42,832 41,430 47,303 41,262 42,943 41,517 47,571
-Inventory Capital
60 day supply of consumables at 100% CF 18,536 19,241 19,215 19,238 19,114 19,266 19,196 19,101 19,205
0.5% of TPC (spare parts) 8,998 10,285 10,708 10,358 11,826 10,315 10,736 10,379 11,893
-Initial Cost for Catalyst and Chemicals 1,536 17,655 17,824 16,782 18,180 19,837 19,559 18,081 19,831
-Land 900 900 900 900 900 900 900 900 900
-Other Owner’s Costs 269,951 308,563 321,240 310,728 354,770 308,782 322,070 311,375 356,782
-Financing Costs 48,591 55,541 57,823 55,931 63,859 55,703 57,973 56,047 64,221
Total Owner’s Costs, $×1000 406,033 475,979 493,217 478,019 538,630 479,443 496,069 480,064 543,098
Total Plant Cost (TPC), $×1000 1,799,676 2,057,085 2,141,601 2,071,519 2,365,136 2,063,076 2,147,136 2,075,831 2,378,545
Specific TPC, $/kWnet 2,681 4,013 – – – 3,990 – – –
Total Overnight Cost (TOC), $×1000 2,205,709 2,533,064 2,634,818 2,549,538 2,903,766 2,542,519 2,643,205 2,555,895 2,921,643
Specific TOC, $/kWnet 3,286 4,941 – – – 4,917 – – –
First Opt. Year COE, $/MW hnet 107.5 155.9 – – – 155.1 – – –
First Opt. Year LCOE, $/MW hnet 136.3 197.7 – – – 196.6 – – –
CO2 Avoided Cost, $/ton of CO2 – 68.1 – – – 66.8 – – –
Total Annualized Expenditures (TAEs) in First Opt. 505.7 560.0 575.3 562.4 615.0 561.9 576.7 563.5 617.8
Year, $ (Million)
Total Annualized Revenue 376.3 287.4 281.5 288.1 248.2 289.9 284.1 289.6 250.3
(TAR)a in First Opt. Year, $ (Million)

Total annualized revenue is evaluated at average market selling prices of all products.

electricity generation. Production of ammonia and methane along with

power, caused the energy conversion efficiency to achieve the value of
36.86% for this design. Net efficiency of power generation reduces to
25.41% (HHV).
In design-4, where more methane is produced as compared to
ammonia, the increased flow of syngas to methanation section lowers
the syngas flow available for Selexol cleaning, resultantly less power i.e.
17.27 MWe in comparison to 20.46 MWe in design-3, is consumed by
Selexol process. Power consumption for the CO2 compression is also
reduced, as the quantity of CO2 separated is less. Only 27.44 MWe power
is consumed in comparison to 32.59 MWe for design-3 and 34.34 MWe
for base case design-2. The O2 requirement is based on the gasification
process, so power consumption by the main air compressors to produce
constant amount of O2 for all cases is same. Power consumption by the
N2 compressor is based upon the requirement of N2 in GT combustor and
Selexol process. In design-4, as the required nitrogen for GT combustor is
less, so auxiliary power consumption by nitrogen compressors is also
less. Keeping in view the above discussion, the auxiliary power con­ Fig. 5. Contribution of different types of costs in COE ($/MW h) in first
sumption is less in design-4, only 175.08 MWe power is consumed as operating year of design-2 (base case).
compared to 217.46 MWe in base case design. Methane production in
large quantity also improves its overall energy conversion efficiency up ARS generator from the coolers of hydrogen and nitrogen compressors in
to 48.58%. The water consumption in design-4 is also low because of ammonia production plant.
small power block and resultantly reduced water consumption in steam In design-5, little amount of syngas directed to methanation section,
condenser, as presented in Table 8. so the cleaning load of syngas in Selexol section remains almost un-
ARS has been integrated with AGR section of design-2, 3, 4 and 5, for altered, hence the auxiliary load of AGR and CO2 compression is
the chilling of lean solvent before CO2 absorber. In this way, auxiliary almost same, as in design-3. After syngas cleaning, a sufficient quantity
load of AGR in the form of chilling duty is reduced, resultantly reduction is transferred to ammonia production section, where additional load of
in overall auxiliary power consumption of the IGCC plant causes an N2 and H2 compression causes a reduction in overall electrical effi­
increase in net electrical efficiency of the plant, as seen in Table 9. The ciency. Furthermore, ammonia has low HHV, so increase in ammonia
net electrical efficiency of the design-2 reaches to 32.61% (with 0.28% production does not causes a major increase in energy conversion effi­
point increase) after integration. The increase in efficiency of the design- ciency. The energy conversion efficiency for this design is 39.07%.
3, design-4 and design-5 is 0.29% point, 0.17% point and 0.24% point, Table 8 provides a detail of auxiliary power consumption by all co-
respectively after ARS integration. Maximum increase in efficiency is generation designs along with the base case design-2 with carbon cap­
found in design-2 and design-3, because of sufficient quantity of flue gas ture and design-1 without carbon capture.
available to power ARS generator. Design-3 provide more hot water in An overall energy balance of IGCC 100% and co-generation designs

16
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 6. Breakdown of annualized expenditures involved in first operating year for various designs of the IGCC system.

Fig. 7. Annualized expenditures and annualized revenue from various designs of the IGCC system.

is provided in Table 10, which has been evaluated by adding all energy Table 11. The first operating year COE and LCOE for both design-1 and
going in to the plant and total energy coming out from the plant [8]. design-2, and CO2 avoided cost for design-2 are presented in Table 11.
The first year COE of the design-1 is 107.5 $/MW h and for design-2
without T&S is 155.9 $/MW h for Pakistani lignite coal. The high
4.5. Economics analysis value of COE without T&S is because of high price of Pakistani lignite
reported [50]. If coal price is set to 18.19 $/ton, as of quality adjusted
An economic analysis of the IGCC designs which includes, TPC, TOC, North Dakota lignite delivered reported [69], first operating year is
variable O&M (including fuel cost) and fixed O&M cost, is presented in

17
A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 8. Annual net CO2 emission from (a) IGCC plant (b) chillers of AGR unit, for design-2, 3, 4 and 5.

assumed 2012 instead of 2016 and, if T&S cost of 9.8$ [45] is added in ammonia plant. The value of $ 372.6 M for design-5 is noted in com­
calculating COE, the resultant value comes out to be 141.2 $/MWh, parison to $ 338.1 M and $ 327.2 M for design-3 and design-4, respec­
which is very close to reported value of COE of 141.3 [8] for lignite coals tively (see Fig. 6). The effect of integration of ARS on capital cost of IGCC
using dry feed Shell technology with carbon capture. The close-ness of designs, based on cost of heat exchanged area of ARS is presented in
these predicted results with the reported data confirms the reliability of Fig. 6. The increase in O&M costs, because of extra burden of cooling
this simulated model and economic analysis. The breakdown of the first utilities and LiBr salt solution of ARS is also presented in Fig. 6.
operating year COE for design-2 (base case) based on the individual cost The annual co-product credit other than electricity comes from the
contributors is presented in Fig. 5. In design-2, the share of TOC is 90.5 production of methane and ammonia in co-generation cases. Based on
$/MW h in COE which is 58% of the total COE. Variable O&M cost the average selling prices (see Table 5) of co-products (methane and
constitutes 8.9% and fixed O&M cost is 15.1% of the total COE (see ammonia) and the quantity produced of these co-products (see Table 8),
Fig. 5). After TOC, the major contributor in COE is cost of coal with its the annual revenue received from design-3, design-4 and design-5 is $
17.9% share. 55.7 M, $ 188.7 M and $ 144.9 M, respectively.
The TPC of design-2 is $ 2,057.1 million (M), with a net power In NETL report [20], the economic indicator was FYCOP for
generation of 512.62 MWe. The specific plant cost is 4,013 $/kWe. In co- ammonia by considering methane as a co-product and vice-versa.
generation designs, the TPC evaluated is $ 2,141.6 M, $ 2,071.5 M and $ Electricity generated from steam turbine was also considered a reve­
2,365.1 M for design-3, design-4 and design-5, respectively. The nue credit to calculate the FYCOP of ammonia or methane. Similarly, in
increased cost of design-3 and design-5, as compared to base case is another report [8] the economic indicator was COE for electricity
because of two additional plants of methane and ammonia production. generating system. In this study, COE or FYCOP are not a suitable option
Ammonia production is the most expensive plant in the form of TPC. The as an economic indicator for co-generation designs because of almost
reason of decrease in TPC of design-4 even after addition of methane and equal production of methane and electricity in design-4 and ammonia
ammonia plant is reduction in the size of GT and whole power block, as and electricity in design-5. Therefore, to perform a comparative eco­
almost half of the H2 rich gas is transferred for methane production. nomic analysis, the economic indicators considered in this study for all
Other reason of the reduction of TPC of design-4 is the reduced size of designs are TAEs and total revenue received by selling all possible
AGR unit, as the major portion of syngas rich in CO after retiring H2S is outputs.
utilized in methane production. The detailed compilation of costs by The first operating year expenditures (i.e., first year capital charge
major process units for all five designs is provided in the supporting and O&M cost including fuel) and revenue credit received by selling all
material. three commodities i.e., electricity, methane and ammonia based on
The variable material maintenance and waste disposal (slag) cost is average selling rates (see Table 5) from all designs are evaluated and
fixed in all cases, the change in total variable and operating comes based presented in Fig. 7 and Table 11. The selling revenue received from the
on the quantity of consumables. The slight increased O&M cost of co- design-2 by selling electricity on average rates of $ 0.08/kWh is $ 287.4
generation cases is because of varied quantity of catalysts used in M. The TAEs for first year operation of design-2 are $ 560.0 M. In co-
shifting of CO, ammonia and methane production processes as shown in generation cases, Design-4 is the best with value of $ 288.1 M single
Table 11. In design-5, H2 rich syngas is used in ammonia production, so year revenue. The second-best design in co-generation category
increased cost of shifting catalyst and ammonia catalyst causes an (without ARS integration) is design-3 with total annual revenue of $
overall increase in initial fill cost of catalysts. The initial fill cost of 281.5 M. The design-5 with annual revenue output of $ 248.2 M is the
design-2 is $ 17.66 M in comparison to $ 17.82 M, $ 16.78 M and $ least revenue generating design, because of high ammonia production
18.18 M for design-3, 4 and 5, respectively, as shown in Table 11. The and less production of revenue generating products (i.e., methane and
decreased initial fill cost of design-4 is because of decreased quantity of electricity). The high revenue from design-4 is because of huge methane
shifting and ammonia catalysts. The annual cost of coal in first operating production and attractive average selling prices of methane in the
year with value $ 100.5 M is same in all cases, as shown in Fig. 6. The market [29].
first year capital charge of design-5 shows higher value, because of Among IGCC co-generation, design-5 is the most expensive with

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. 9. (a) Variable market and (b) variable production scenarios, for various designs of IGCC cogeneration system.

value of $ 615.0 M in comparison to design-3 and 4 with TAEs of $ 575.3 emission is less, in case of ARS integration with same IGCC plant.
M and $ 562.4 M, respectively, as shown in Fig. 7. The huge expendi­ In co-generation designs-3, 4 and 5, the production facility for the
tures of design-5 are due to large size of additional ammonia plant and carbon conversion to methane product was not penalized, as the end use
syngas cleaning expenditures, as the cleaned H2 rich syngas is used in of the methane is unknown [20], among valuable chemical production,
ammonia production. The lower total expenditures of design-4 are due like methanol, formaldehyde, formic acid and chloroform in addition to
to low cost of methane plant even after including methane purification direct burning for energy production. For the co-generation cases, the
and compression, as compared to the cost of ammonia plant [20]. burden of carbon mitigation falls on the end-user, however CO2 emission
ARS is integrated with design-2, 3, 4 and 5 to partially meet the during production and purification of methane has been considered in
cooling requirements of AGR Selexol process. Addition of ARS causes a the evaluation of total emissions. In this study, total annualized CO2
reduction in total auxiliary power and, hence the reduction in capital emission from all 100% power and co-generation cases is presented in
cost of related systems. Similarly, decrease in total auxiliary power of Table 8. Annual CO2 emission from the base case (design-2) is 426,665
the plant causes an increase in net MW h of the design-2, 3, 4 and 5. Even tons/year, which is in close agreement with literature [8] for the same
after additional burden of cost of ARS into COE of IGCC 100% power type of plant. Annual CO2 emission from design-5 is minimum with
design-2A, the resultant first operating year COE of the ARS integrated value 225,706 tons/year, as a large portion of syngas is utilized in
IGCC plant is slightly reduced because of increased MW hnet of the ammonia production instead of burning in combustor of GT. The second
electricity. The estimated COE of ARS integrated design-2A was 155.1 least CO2 emitter design is design-4 in which 314,069 tons/year CO2 is
$/MW hnet in comparison to 155.9 $/MW hnet for design-2. The ARS released in the environment, as shown in Fig. 8(a). The integration of
integrated IGCC cases, i.e. design-2A, 3A, 4A and 5A show slight in­ ARS with base case causes an increase in total MW hnet, which resulted in
crease in TAEs, and this increase is in capital and O&M costs, as shown in decrease in specific CO2 emission from the IGCC plant as shown in Ta­
Fig. 6. Increase in MWnet, because of reduction in auxiliary power caused bles 8 and 9.
an increase in MW hnet, hence more electricity is available to sale, which The impact of ARS integration in the reduction of CO2 emission is
causes an increase in total selling credit with ARS integration, as shown assessed by evaluating total CO2 emission from the conventional vapor
in Fig. 7. compression chillers using electricity as utility in the chiller. The
reduced CO2 emission after integrating ARS with AGR of the IGCC
4.6. Environmental analysis design-2, 3, 4 and 5 is presented in Fig. 8(b). A total 13,336 ton/year
CO2 emission reduction has been achieved in design-3, after ARS inte­
Air emissions include, evaluation of total emission of SO2, NOx, gration with lean solvent chilling in AGR section. Similarly, design-2
particulates, Hg and CO2 from the IGCC plant [8]. CO2 is a dangerous showed a reduction of 13,070 ton CO2 emission annually after ARS
GHG due to its huge volumes, and hence higher environmental impacts integration, as presented in Fig. 8 (b).
causing global warming. The annual CO2 emissions from the combustion
of syngas is assessed from all designs (with and without ARS integra­ 4.7. Scenarios of variable production and fluctuating market prices for
tion). Cost of carbon avoided is evaluated using Eq. (14), to measure the various co-generation designs
additional expenses of carbon capture and is expressed in $/ton CO2.
Instead of assuming COE for IGCC non-capture case for the calculation of Performance analysis of co-generation designs based on the varied
carbon avoided cost, the IGCC power plant with same technology is selling price of the products helps to design best combination. The cause
simulated and complete economic analysis has been performed, as of vulnerability of market can be the price of one product or it might be
presented in Table 11. The first operating year COE of the IGCC without because of overall selling price of all products from the IGCC co-
carbon capture (i.e., design-1) was estimated at 107.5 $/MW hnet. The generation plant. Revenue obtained from the selling of the products in
CO2 emissions from the reference plant were 762.0 kg/MW hnet. The cost high methane, high ammonia and high electricity markets for various
of carbon avoided is 68.1 $/ton for the base case. The avoided cost for co-generation designs have been presented in Fig. 9 (a). Design-4, with
ARS integrated IGCC (i.e., design-2A) is 66.8 $/ton, as the specific CO2 high methane production gives high revenue than all other designs, and

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

the performance of this design is favorable for high methane market. The 14% reduced revenue as compared to design-2. The annualized revenue
performance of design-3 is favorable for high electricity markets. It was to expenditure ratio of co-generation design-4 is more than design-2
also observed that, the performance of design-5 remained poor than (0.57 vs 0.51) in high methane market scenario. The design-4 with
design-4 even for the huge production of ammonia for high selling pri­ methane and electricity as major outputs has shown best performance
ces, but it gives more revenue than design-3 (a major electricity pro­ for low-quality coals. The maximum revenue can be obtained from
ducing design). Among all co-generation scenarios for varied market design-4 for average and low market prices and from design-3 for high
trends for selling prices of methane, ammonia and electricity, the market prices. It is observed that, the increased production of methane
design-4 has given best performance in high methane and high ammonia and ammonia, as in design-4 and design-5, respectively, causes a
markets. Design-4 is second best with respect to revenue after design-3 decrease in the CO2 emission. For the co-generation cases, the burden of
even in high electricity markets, as shown in Fig. 9 (a). The other way carbon mitigation falls on the end-users, as the consumer of the product
to study the performance of the IGCC co-generation designs is by fixing is unknown. With the integration of ARS, 0.28% point increase in effi­
the overall prices of all the products to average, low and high level to ciency of the base case took net electricity efficiency up to 32.61% HHV.
evaluate the total revenue obtained from various designs. In Fig. 9 (b), Similarly, the increased MW h due to reduced auxiliary power by the
behavior of three co-generation designs is presented in average, low and ARS integration caused slight increase in revenue of the co-generation
high selling prices of all products. As presented in Fig. 9 (b), the annu­ designs. Reduced load on vapor compression refrigeration, because of
alized revenue obtained from design-4 is more than other designs in ARS integration caused a reduction of CO2 emission of 13,336 ton/year
average and low markets, but design-3 gives maximum revenue during in design-3 and 13,070 ton/year in design-2.
high market trends. Design-5 performs poor in all type of markets. The The high value of first operating year COE of 155.9 $/MW h without
all-time best design is design-4 as shown in Fig. 9 (a) and (b), which sequestration for Pakistani lignite indicate that more efforts are required
gives better performance during high methane, high ammonia markets, to develop local resources of coal, so that competitive price of fuel
as shown in Fig. 9 (a), and also performs best during average and low delivered at plant can cause a drastic decrease in COE. This is a pre­
markets, as shown in Fig. 9 (b). Study of this type of market trends, for liminary study, derived from available literature on low quality coals.
the performance assessment of various designs of an IGCC co-generation The base dollar ($2011) selected for this study gives actual representa­
systems are important for decision makers to choose the best design for tion of the low-quality based IGCC plant, because of available data. This
investment, with 17% flexibility in prices for methane, 33% for can be updated on recent developments in future investigations.
ammonia and 25% for electricity. As presented in Fig. 9 (a) and (b), the
design-4 could generate a revenue of $ 317.1 M in high methane sce­ CRediT authorship contribution statement
nario. High markets of all commodities could take that annualized
revenue to its highest level of worth $ 349.2 M for design-3 and $ 345.5 Adnan Muhammad: Conceptualization, Methodology, Software,
M for design-4. Validation, Formal analysis, Investigation, Data curation, Writing –
original draft, Writing - review & editing. Zaman Muhammad:
5. Conclusions Conceptualization, Formal analysis, Investigation, Writing – original
draft, Writing - review & editing, Supervision, Project administration,
IGCC power plant with 100% power and co-generation, based on Funding acquisition. Atta Ullah: Writing – original draft, Formal anal­
Pakistani lignite coal was simulated using Aspen Plus®. Performance ysis. Rizwan Muhammad: Writing – original draft, Methodology,
analysis of IGCC power plant with possible options of co-generation Formal analysis. Neelam Ramzan: Methodology, Software.
(methane and ammonia along with electricity) was the main objec­
tive. Various production designs of IGCC co-generation system were Declaration of Competing Interest
simulated and a comprehensive economic analysis was performed to
find the best possible design with respect to maximum revenue gener­ The authors declare that they have no known competing financial
ation, lowest GHG emissions and competitive running expenditures of interests or personal relationships that could have appeared to influence
the particular design. The developed designs of IGCC co-generation were the work reported in this paper.
assessed on varied production decisions and market prices of the prod­
ucts. Moreover, ARS is integrated with base case and co-generation Acknowledgement
designs to partially share the chilling load in AGR section.
The low-quality Pakistani lignite coal with 12% moisture level at the This research was initiated for the feasibility studies of power gen­
time of gasification can reach an efficiency of 32.33% (based on HHV) eration based on the indigenous Pakistani lignite resources. The funding
with 92% carbon capture, for 100% power generation mode. The base support was provided by National Research Program for Universities
case (i.e., design-2), resulted in a first operating year COE of 155.9 (NRPU, No: 6090/Federal/NRPU/R&D/HEC/2016) from Higher Edu­
$/MW h without taking into account costs associated with CO2 cation Commission (HEC) of Pakistan.
sequestration. Economic analysis of IGCC 100% power (i.e., design-2)
and one of the co-generation cases (i.e., design-4) indicated that, in Appendix A
average market scenario, the co-generation design-4 with almost equal
revenue to expenditure ratio of 0.51, releases about 25% less CO2 in the .
environment. Similarly, another combination of co-generation (i.e.,
design-5) releases almost half CO2 in the air but at the cost of almost

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. A.1. Flowsheet of IGCC 100% power system compiled in Aspen Plus®.

Fig. A.2. Flowsheet of IGCC co-generation system compiled in Aspen Plus®.

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. A.3. Flowsheet of coal drying, gasification and particulate removal compiled in Aspen Plus®.

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. A.4. Flowsheet of dual stage Selexol process, compiled in Aspen Plus®.

Fig. A.5. Flowsheet of Air Separation Unit (ASU), compiled in Aspen Plus®.

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. A.6. Flowsheet of Methane Production, compiled in Aspen Plus®.

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. A.7. Flowsheet of Ammonia Production, compiled in Aspen Plus®.

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A. Muhammad et al. Energy Conversion and Management 248 (2021) 114782

Fig. A.8. Flowsheet of Power Generation, compiled in Aspen Plus®.

Appendix B. Supplementary data [15] Li Y, Zhang G, Yang Y, Zhai D, Zhang K, Xu G. Thermodynamic analysis of a coal-
based polygeneration system with partial gasification. Energy 2014;72:201–14.
https://doi.org/10.1016/j.energy.2014.05.025.
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