How-to, Tips and Articles: The Clean Coal Technologies With Coproduction of Power and Methanol

The Coal-based chemical process is still indispensable in modern society due to the worldwide vast reserves and popular price of coal. Power generation and chemical production from coal still play an important role in the global chemical industrial market. Electricity generation and chemical production from coal is still the trend as long as the coal is plentiful and inexpensive. Modern chemical industry aims at sustainability and hence the development of clean coal technologies is critical.

Coal-based methanol economy, as an attractive liquid transportation fuel as well as an essential intermediate chemical feedstock, can fill a possible gap between declining fossil fuel supplies and movement toward the hydrogen economy. The integrated gasification combined cycle (IGCC) power plant with methanol production is simulated by Aspen Plus. Within the plant, firstly, the coal is fed to a pyrolysis reactor, and the volatile matter is fed into an oxy-combustion reactor, while the char is gasified in an entrained flow gasifier. The heat is used to produce electricity, while the syngas is converted to methanol. The integral plant consisting of an air separation unit, oxy- combustion of coal, gasification of char, electric power production, carbon capture and conversion to methanol has been designed and optimized by using the Aspen Plus package. The optimization includes the design specification, process heat integration using energy analyzer toward a more efficient clean-coal technology with methanol production. Multiple methods including life cycle assessment, sustainability metrics, and multi-criteria decision matrices are applied to analyze the sustainability of a certain clean-coal based IGCC power plant with methanol production.

Chemical looping technology is a new method utilizing inherent CO2 capture to address the concerns of growing levels of atmospheric CO2. The studied IGCC plant is compared with a conventional IGCC power plant to better understand the feasibility of the technology. A multi- criteria decision matrix consisting of economic indicators as well as the sustainability metrics shows that methanol and steam productions besides the power production may improve the overall feasibility of clean coal technology.

The goal of this work aims at developing the use of abundant resources of coal energy in the following aspects:

Energy security
Reduction of Greenhouse Gas emission
Co-production and kinetics study in coal-based chemical processes
Sustainability analysis

CHAPTER 1 INTRODUCTION

Coal plays an important part in worldwide energy markets due to its vast resources and affordable price. Currently, about 39% in the U.S. and 41% of global electricity generation come from coal- fired power plants [1]. As Roan et al. [2] suggested that a possible decline in recoverable fossil resources and movement toward a hydrogen economy could cause a time gap. Then the methanol production from coal may be one of the best options for filling the gap because of the steady and low cost of coal and its impact on the national energy security. Using coal as the feedstock will cause some issues such as environmental pollutant. While the traditional coal technique combined with methanol production which will fixed carbon from coal and help to reduce the greenhouse gas. Such a clean-coal technology makes great efforts on overcoming the environmental issues.

As a result, coal-based methanol would be an ideal hydrocarbon fuel which can be used in different fields like transportation and manufacturing industry. [2]. Methanol can also be a valuable intermediate chemical feedstock for producing chemicals and biodiesel. Because coal is still an abundant and affordable energy source, the development of sustainable and efficient clean coal technologies with carbon capture are essential in producing coal-based power, steam, and chemicals [3]. Modern coal-based chemical industry efficiently converts coals into clean gaseous fuel which can be used for productions of power and chemicals. Currently, almost 97% of the world's coal- fired capacity is made up of pulverized coal (PC) power plants [3]. Integrated gasification combined cycle (IGCC) is a well-known coproduction technology developed capable of producing power and other feasible chemicals. It largely improves the energy efficiency and reduces the emissions compared with the traditional pulverized coal-fired system. The efficiency of the IGCC is about 36-39% while the conventional coal plants operate at 32-38% efficiency [4]. Gasification plant databases prepared by DOE-NETL compile information on the technologies and investments in major industrial coal gasification projects throughout the world [5].

1.1 Literature Research

Sustainability analysis assesses the nonrenewable material and energy depletions, as well as the Green House Gas (GHG) emissions with respect to the unit mass of primary product, and may provide a guideline on how to design sustainable processes. The strict standards for GHG emissions and high carbon fee are required for coal power plants. One efficient way to control GHG emissions is “oxy-combustion” which has been applied in the conventional pulverized coal power plants as well as in IGCC, from which CO2 can be easily separated [6-9]. Siyu Yang et al [10] presented an integrated framework for modeling three coal-based energy and methanol synthesis processes as well as optimized these processes by calculating exergy efficiency and estimated sustainability.

Modern researches of coal technologies mostly concentrate on carbon capture, process optimization, and kinetics modeling to simulate the process. Govin et al. [11] proposed a one- dimensional model and found an optimized feedstock conditions by parametric studies.

Consecutively, two-dimensional [12] and three-dimensional [13] models for entrained flow coal gasifier were developed to predict gas temperature profile and the compositions of the output and compare with measured values. After a macroscopic model was built, sensitivity analysis finds out how the specific operation conditions impact coal gasification; for example, Yang et al. [14] reported the impact of a single parameter such as pressure on the feasibility and possible improvements of the plant.

1.2 Objective

This work analyzes the feasibility of clean coal technologies by studying a well-designed IGCC power plant which mainly includes entrained flow gasification, power generation, carbon capture and methanol production. The objective of this study is to assess the feasibility of coproducing methanol in a commercial scale coal-based power plant with carbon capture unit and entrained-flow coal gasification using a kinetics-based model. This study also performs a cradle-to-gate life cycle assessment for GHG emission and energy consumption from raw material extraction, transportation, gasification through power and methanol productions. The syngas produced by coal gasification is supplied to the methanol synthesis process. Capital cost, operating cost, and energy requirements are used to evaluate the techno- economic performance of this clean coal energy technology with methanol co-production. Another novel clean coal technology called Chemical Looping (CL) technology is discussed briefly as a possible near-future technology in power and chemical productions.

1.3 Motivation

The goal of this work aims at developing the use of abundant resources of coal energy in the following aspects:

Energy security
Reduction of Greenhouse Gas emission
Co-production and kinetics study in coal-based chemical processes
Sustainability analysis

CHAPTER 2 METHODOLOGY

2.1 Aspen Plus

The studied and based cases are all designed and simulated with Aspen Plus package, which consists of various optimization tools. The Soave-Redlich-Kwong (SRK) and IDEAL [18] thermodynamic property methods and related reaction kinetics data are used in the design. The coal-based IGCC power plant with methanol production has been analyzed by its sustainability, life cycle assessment, and techno-economic analysis.

2.2 Sustainability Analysis

As the modern society and chemical industry develop, the concept of sustainability is raised to guarantee the conservatively and wisely use of the finite resource with minimal negative effects on the environment, economic, energy and human health. Therefore, ways of measuring the degree of sustainability for a certain process known as sustainability indicators and metrics are proposed and employed in the analysis. The following sustainability metrics are estimated [15,16]: “

Material intensity (nonrenewable resources of materials depleted/unit mass of products)
Energy intensity (nonrenewable energy depleted/unit mass of products)
Potential environmental impact (CO2e emissions/unit mass of products)
Potential chemical risk (toxic emissions/unit mass of products)”

Besides, the fresh water usage is also estimated as another sustainability indicator. For estimating these metrics material and energy balances as well as carbon dioxide equivalent (CO2e) emissions, which considers all the other greenhouse gasses are taken into account. The material, energy, and CO2e emissions are then normalized per unit of mass/energy of the product, making them capacity independent for comparison with similar processes. Energy intensity and potential environmental impact are calculated by Aspen Plus [16,17]. The carbon equivalent emission and environment impacts are partially estimated by “Carbon Tracking” with the data coming from US-EPA-Rule-E9- 5711, US-EPA’s (CO2E-US) and the fuel source of natural gas. Net carbon fee is estimated by CO2e fee/tax of $10/MT CO2e [18,19]. “Potential chemical risks” are estimated by the Life Cycle Assessment tool “GREET” [20,21].

2.3 Life Cycle Assessment

International standards for LCA are defined by ISO 14040 and 14044 which stipulate four steps: “(1) Goal and scope definition, (2) Life Cycle Inventory (LCI) [21,22] (3) Life Cycle Impact Assessment (LCIA) and (4) Interpretation [21,23-24].” These standards outline requirements and guidelines for all these steps [23].

The definition and scoping of goal determine the primary and secondary products, establish the boundaries for the process and declare the environmental effects that are to be reviewed. In the LCI analysis, the uses of energy, water, and raw materials are estimated accompanied by the environmental releases. The third step of LCA is the impact assessment. In this part, the data collected from inventory analyses are translated into visualized indicators including direct potential human and ecological effects. The last step is the interpretation of the inventory analysis results based on the environmental impacts of the products. At the same time, all the uncertainties in the LCA are addressed. Assumptions are made in the boundary, data, operations and criteria factors before the life cycle assessment starts [23,24].

This study evaluates the environmental impacts of clean-coal technology with power and methanol productions using the LCA with the system boundary of “cradle-to-gate” (Figure 1), which means that the assessment will begin with the extraction of raw material, transportation, and productions of power and methanol, and exclude the assessment of usage of the products. All needed data and methodologies come from Aspen Plus, GREET modeling, and published work in the literature. The core operations of the integral plant contain coal gasification, methanol production, and power generation.

Figure 1 Cradle-to-Gate system boundary for the life cycle assessment of clean-coal technology with methanol production.

2.4 Techno-Economic Analysis (TEA)

Techno-economic analysis is based on the discounted cash flow diagrams for an assumed competitive operation of twenty years after the construction of the plant. Maximum Accelerated Cost Recovery System (MACRS) is used for estimating depreciation. Purchase costs of equipment are estimated by using the CAPCOST [25] program with the 2016 Chemical Engineering Plant Cost Index (CEPCI) [26]. Besides the deterministic analysis, stochastic evaluations are also performed by the Monte Carlo Simulations based on the possible deviations of the major economic data matrix.

CHAPTER 3 IGCC-BASED COAL POWER PLANT

This plant includes seven sections represented by hierarchies (Fig. 2), which are Air Separation Unit (ASU), steam generation, coal gasification, Water Gas Shift (WGS) unit, power generation, methanol production and carbon capture unit. These seven sections are connected with material, heat and work streams to each other. The process hierarchy flow diagram and block flow diagram (BFD) of the integrated plant are shown in Figures 2 and 3, respectively.

Figure 2 The hierarchy process flow diagram of the integrated clean-coal technology with methanol production.

Figure 3 Block flow diagram of the integrated clean-coal technology with methanol production (MT: metric tonne)

Air, water and coal are the inputs of the integral process. The ASU produces 401.69 MT/day of O2 and 1309.33 MT/day of N2 by using 1731.02 MT/day of air. Steam generation unit produces 10 MT/day of steam by using the boiler feed water. 500 MT/day Powder River Basin (PRB) coal is fed into coal gasification by which 880.80 MT/day of syngas is produced together with 30.87 MT/day of wastes including solid waste and tail gas. Then the syngas is fed into the WGS unit. After the WGS reaction, 91.8% of CO2 in the mixed gas is captured in carbon capture unit. The product gas containing mostly CO, H2 and CO2 is fed into methanol production unit and produce 207.99 MT/day of methanol. All the available heat streams are directed into the power generation unit where 40.11 MW of electricity is produced, as seen in Figure 2.

3.1Air Separation Unit (ASU)

Air separation is a well-known technology which provides high-quality oxygen and nitrogen. ASU is integrated in the coal gasification process. Its function is controlling the amount of oxygen in gasifier for “partial oxidation” and participating in oxy-combustion. Oxy-combustion utilizes the pure oxygen in fuel combustion to avoid the dilution of effluent by the nitrogen and facilitate easy capture of CO2. Oxygen and nitrogen from the ASU can be valuable products.

This plant utilizes 1731.02 MT/day of air with the assumed components of 21% oxygen and 79% of nitrogen by volume to provide oxygen in the oxy-fuel combustion. The cooled air is fed to a low-pressure separating column and a high-pressure separating column step by step. Both columns work interactively and separate oxygen and nitrogen respectively. With the higher boiling point (- 183 oC), oxygen condenses out of gaseous streams. The ASU produces 401.69 MT/day of 95% O2 and 1309.33 MT/day of 99.9% N2. The oxygen is delivered to the coal gasification unit as one of the main feedstock, while the nitrogen is sold as a byproduct.

The low-pressure column LPT101 has 60 stages with sieve trays. The column has a partial condenser and a reboiler. The mole purity of oxygen in the column is adjusted by varying the vapor side stream rate. The high-pressure column HPT102 has 60 stages. In a design specification block, by varying the ratio of liquid flow to feed flow rate, a mole purity of 99.9% of N2 and a mole purity of 95% of O2 are achieved. Table 1 shows the specifications and operating conditions for the columns. Process flow diagram and the stream table of the ASU are shown in Appendix A in Figure A1 and Table A1.

Table 1 Column specifications and results for low pressure (LP) and high pressure (HP) columns.

3.2 Coal Gasification

Gasification is a method to convert carbon-based energy source into gaseous fuels such as syngas and flue gas. Due to the rich coal resources, coal will keep being the dominant feedstock in the worldwide gasification market. Gasification and Syngas Technology Council (GSTC) has reported that the existing gasification facilities are currently based on coal as the feedstock (Figure 4). In the forecast, it is seen that the number of coal gasification plants will stay growing.

Figure 4 Gasification facilities classified by feedstock [27].

Coal gasification is also the core technique of clean coal technologies. It can convert coal into liquid transportation fuels, power and chemicals. Comparing with direct coal combustion, coal gasification releases less gas, which stands for the simplification of facilities and the reduction of capital cost. Basically, Coal gasification can be carried out by fluidized bed gasifier, fixed or moving bed coal gasifier and entrained flow coal gasifier based on the way that coal particles contact with gasification agents. Fluidized bed gasifiers keep the solid fuel particles suspending in upward-blowing jets of air and resulting in a turbulent mixing of solid and gas phase. This mixing makes the bed in the gasifier look like a bubbling fluid and helps increase the rate of heat transfer and reactions. The sufficiently fluidized bed acts like liquid and since reflects some characteristics of the fluid.

Figure 5 Fluidized-bed coal gasifier [28].

The particle size of the feedstock of the fluidized-bed gasifier is normally between 0 to 6mm. Small particle size is beneficial to maintain the fluidization and increase the heat transfer surface. Coal is fed into the top of the gasifier while the steam or oxidant is fed at the bottom of the gasifier at an appropriate speed. The coal particles suspend at a uniform and moderately high temperature in the gasifier. The advantages of fluidized coal gasifiers are that they are capable of gasifying a wide range of feedstocks at a relatively stable condition. However, compared with entrained flow coal gasification, the carbon conversion is lower (90% - 95%). US Energy Government indicates that “The Clean Coal Technology Program led to the initial market entry of 1st generation pressurized fluidized bed technology, with the capacity of around 1000 megawatts installed” [29].

Another coal gasifier is fixed or moving-bed gasifier, shown in Figure 6. The coal is fed at the top of the reactor bed, and the oxidants or steam enters the gasifier at the bottom of the reactor.

Coal particles and gasifying agents mixed counter-currently. The ash is disposed from the gasifier bottom. The input coal particles travel slowly down and contact with the oxygen-rich gas that going upwards from the inlet of the gasifier. Typically, the reactor bed is separated into different parts with different functions

Figure 6 Moving-bed coal gasifier. [30]

Moving-bed coal gasification works at a relatively high equipment efficiency and requires a smaller amount of oxidant. This technique fits for the coal with high moisture and reactivity. The products usually contain high content of methane and hydrocarbon liquids. Products purification and coal fines treating will somehow increase the capital cost.

Another well-known coal gasification is entrained-flow coal gasification. Unlike other gasification, it allows the raw materials and the oxidant or steam entering the gasifier co-currently. Coal fines and gasification agents are fed at the top of the gasifier and mix with each other smoothly. The oxidant or steam entrain the coal particles and forms a dense cloud which helps the mixture moving through the entire gasifier. The entrained flow coal gasification requires a relatively high temperature and pressure to react. This results in a high reaction rate and carbon conversion (98 -99.5%). Figure 7 shows the scheme of Texaco gasifier equipped with a quench chamber with the coal water slurry (CWS) as the feedstock. In this work, the coal gasification hierarchy of IGCC power plant is demonstrated mainly based on entrained flow coal gasification model, mainly due to high reaction rates and carbon conversion.

Figure 7 Texaco entrained-flow coal gasifier [31].

Coal gasification unit is the major part of the plant. The block flow diagram of coal gasification is shown in Figure 8. The entire coal gasification process can be split into three parts: coal and char pyrolysis, oxy-combustion, and char gasification. In this model, 500 MT/day of PRB coal [32] is utilized. The pressure of the coal is 1.1 bar and the temperature is 25oC. The diameter of pulverized coal is typically less than 500 μm [33].

Figure 8 The block flow diagram of coal gasification.

Firstly, the coal is pyrolyzed in reactor R201 at 1.1 bar. The outputs are fed to the next pyrolytic reactor R202 at 24.3 bar. A separator S201 separates the gas phase and the solid (char) phase. The solid phase reacts further in an R-stoic reactor R203 where the char is converted to volatile substances, solid and ash (Figure 8). This part is called coal and char pyrolysis. Secondly, the separated gaseous constituents are introduced into the combustor R204 and burned with the oxygen coming from the ASU, which is known as oxy-combustion. The outputs of R203 and R204 combined with the steam enter the entrained flow gasifier R205 where the main gasification reactions occur. The gasifier operates at 24 bar with the diameter of 1.5 meters and length of 3.1 meters. This entrained flow gasifier contains two sections. The upper part is for coal gasification while the lower part is a quench chamber. Coal, steam and oxygen are the main feedstocks. Firstly, pulverulent coal is mixed with water to achieve coal-water slurry, which is fed along with the oxygen into the top section concurrently. In this part, there is a special refractory material lining to resist the severe operating environment and strong turbulence [11,18,31, 34-35]. The product of coal gasification is separated into 899.33 MT/day of syngas and 56.84 MT/day of solid waste consisting mainly ash, sulfur, and carbon by the separator 202.

3.2.1 Coal Pyrolysis

Coal processing is related to high-temperature reactions that are operated from 1000 oC to 1500 oC and produces a large amount of heat indicated by heat streams of Q1, Q3, and Q4 by the exothermic reactions taking place in reactors R201, R202 and R204, as shown in Fig. 8. Heat stream Q1 is utilized as the heat source of the boiler in steam generation unit, while heat streams Q3 and Q4 are used in power generation. The stream table of coal gasification is displayed in Figure A2 and Table A2 in the Appendix.

As Figure 9 displays, 500 MT/day of bituminous coal is fed into the first pyrolysis reactor R201 where the first pyrolysis reaction (R1) takes place

Coal → Char + CO + H2 + H2O + CO2 + CH4 + H2S + N2 + C6H6 (R1)

Figure 9 Flow diagram of coal and char pyrolysis with quantified streams and reaction conditions.

The first pyrolyzer R201 is operated at 1050oC and 1.1 bar and the coal is converted into 136.4 MT/day of volatile matter and 363.6 MT/day of char1. The second pyrolyzer R202 converts char1 into char2 at 24.3 bar. After the two-step coal pyrolysis, 500 MT/day of coal is converted to 107.79 MT/day of volatile matter and 392.21 MT/day of char2. The two-phase outputs from R202 are separated by a separator S201. The volatile matter goes to the combustor and the solid phase char2 enters an R-stoic reactor (R203) where the char2 pyrolysis takes place represented by reaction (R2).

Char2 →→ C + S + H2 + N2 + O2 + Ash (R2)

The stoichiometric parameters of R2 are determined by the subroutine USRKIN. The Redlich Kwong Soave (RKS) thermodynamic model is applied. Table 2 displays the components’ attributes of coal and char1. Components attribute of char2 is estimated by the element mass conservation by the subroutine USRKIN.

Table 2 Component attributes of Powder River Basin (PRB) coal and char1 in wt% [32]

In the coal pyrolysis, two R-yield reactors are used. These reactors require the yields of the components of the product to simulate the pyrolysis reactions. The yields of char1 come from the experimental data. [35, 36] The adjusted yields are calculated by Eq. (1) in the user subroutine USRPRES. All the relative compositions of gas components are treated as constant.

Y2 = Y1(1- aln Pt ) (1)

where Y1 is the total yield of gaseous products at 1.1 bar, Y2 is the total yield of gaseous products at the pressure of system Pt, and a is a constant which is 0.066 in this model. The yields of char1 and char2 are listed in Table 3.

Table 3 Estimated yields of coal pyrolysis products in reactors R201 and R202 used in the model.

3.2.2 Oxy-Combustion

After coal and char pyrolysis processes, the gaseous products from the pyrolysis reactor R202 are fed into the combustor R204 where oxy-combustion takes place (Figure 9). 107.79 MT/day of gaseous product burned completely in 383.99 MT/day of oxygen at 1200 oC and 24.3 bar. Reactions

R3 to R6 show the major reactions in reactor R204.

C6H6 + 7.5 O2 → 6CO2 + 3H2O (R3)

H2 + 0.5O2 → H2O (R4)

CO + 0.5O2 → CO2 (R5)

CH4 + 2O2 → CO2 + 2H2O (R6)

The reactions are fast at the high temperature and the conversion of each reactant is regarded as 100%. The oxy-combustion converts the hydrocarbon to carbon dioxide and water and helps the char gasification to occur as shown in Figure 10.

Figure 10 Flow diagram of oxy-combustion with inputs and outputs.

3.2.3 Char Gasification

Char gasification takes place in an R-Plug reactor R205 representing an entrained flow coal gasifier. The feed is at 1050 oC and 24.3 bar and contains 491.78 MT/day of mixed gas with mainly CO2 and H2O produced by oxy-combustion, 10 MT/day of additional steam generated by Steam Generation Unit (SGU) and 392.20 MT/day of gas-solid mixture coming from char pyrolysis in reactor R203. The gasifier operates at 1500oC and 24.3 bar. At the outlet of the gasifier, 899.33 MT/day of syngas is produced which includes 47.75% CO, 1.46% H2, 22.03% H2O, 28.76% CO2 and little of CH4 and N2. Meanwhile, 5.57 MT/day of coal residue containing 5.28 MT/day of sulfur, 0.29 MT/day of carbon and 25.31 MT/day of ash are produced. Table 4 shows the inputs and outputs of the gasifier R205. According to Table 4, the input and output of solid carbon are 172.06 MT/day and 0.29 MT/day respectively. The carbon conversion is improved to 99.8% by using entrained flow coal gasifier.

Table 4 Mass flow of inputs and outputs of gasifier.

Ten reactions R4 to R13 are considered in the char gasification and displayed in Tables 5 to 7. Reactions R7 to R11 are heterogeneous, while others are homogeneous. The heterogeneous reactions involve the solid carbon and sulfur reacted the with the gaseous phase at the surface. The accuracy of the predicted product distribution is highly dependent on the kinetic data used [18,34].. All the heterogeneous reactions are assumed to be surface reactions. As a consequence, the unreacted-core shrinking model is utilized to be compatible with the kinetic data [40]. According to this model, ash layer diffusion, gas film diffusion effects, and chemical reaction effects are considered. The overall reaction rate of heterogeneous reactions is expressed by:

where Jr is the reaction rate in g carbon/(cm2 of coal particle surface s), kdiff is the gas film diffusion constant. ks is the surface reaction constant. kd,ash is the ash film diffusion constant which depends on kdiff and ash layer voidage 𝞮: kd,ash = kdiff 𝞮^n , where n is a constant between 2 and 3 [38]. In this work, 𝞮 is equal to 0.75, and n is 2.5. y is expressed by y = rc/r where rc and r represent the radius of the unreacted core and the radius of the entire particle containing the ash layer. Pi - P* is the partial pressure of ith-component considering the reverse reaction [35,37]. Table 5 lists the heterogeneous reactions and their kinetic data. Table 6 shows the values of Keq of Reactions 8, 10 and 11 [35]. In this model, the chemical equilibrium is estimated in a single R-Gibbs reactor which will provide the data of components during the gasification. At the same time, homogeneous reactions take place in the gasifier. Table 7 displays the kinetic data for these reactions which are used in the user subroutine USRKIN. All the heterogeneous reaction rates are in the unit of kmole/(m s).

Table 5 Kinetic data of the heterogeneous reactions, [34, 35] where T is the temperature, Pt is the total pressure, and dp is the diameter of coal particle which is 500 µm , Pi ,Pi* are the partial pressures, atm

Table 6 Equilibrium constants Keq of Reactions 8, 10 and 11 [35]

3.3 Steam Generation

Steam is partially used as the gasifying agent in the entrained-flow gasifier. The entire process also requires steam as the utility which will be purchased from the utility department. Steam generation unit supplies the steam required in coal gasification. At 1.01 bar and 25oC, 10MT/day of boiler water is fed into a boiler to produce steam. The boiler consumes 14.58 MW of the heat and produces 10 MT/day of steam at 300oC and 1.01 bar. The steam is used as the intermediary in the entrained flow coal gasifier. As the heat streams Q1 and Q2 are utilized as a part of heat integration, this helps reduce the cost of operation and GHG emissions. The PFD and the stream table are displayed in Figure A3 and Table A3 in the Appendix.

Table 7 Reaction rates of homogeneous reactions.

3.4 Power Production

Currently in the US, using coal to generate electricity is still a considerable option. Although the concern about the greenhouse gas emission and other environmental issues is growing, utilization of coal for power generation is still the trend in the foreseeable future due to its cheap price and vast reserves. US Energy Information Administration (EIA) [43] collects the preliminary data for electricity generation by different energy sources for 2016 (Figure 11). 30.4 % of US electricity power is produced by coal by 2016. As the conscious of environmentally friendly and green become strong, developing clean coal technologies to generates electricity is placed on the agenda.

Figure 11 Electricity generation in US by different energy sources [43].

In traditional coal power plants, milled coal fines are burned in the pulverized coal combustion (PCC) system. A boiler utilizes the produced heat and hot gas convert water into steam, and the expend of steam drives the blades of turbine rotates at very high speed and generates electricity.

Things have changed since people have started to realize the economic value of co-production and multiple chemical processes coupled with electricity generation from coal. As a result, syngas and other chemical production are combined with conventional power production plants.

In this integral coal-based combined cycle power plant, part of the heat that comes from the combustor, pyrolysis, and methanol production is used in the power generation unit. The product of the coal gasification is mostly hot syngas which carries large amounts of heat, which can be used to produce electricity with a gas turbine. 2495 MT/day of recycling water is used as steam and cooling water. Two steam turbines and one gas turbine are utilized. Figure 12 shows the block flow diagram for the power production unit.

2270 MT/day of recycling water is pumped by P1 at 25°C and 1.01 bar to the boiler, which operates at 120 bar. 101.82 MW of heat gathered from coal gasification unit, steam generation, and methanol production unit is used in the boiler to convert the water to the steam used in the first steam turbine (T1) to generate 27.32 MW of electricity. At the same time, the hot gas produced by the coal gasification unit is injected into a gas turbine (T2) which generates 11.51MW of electricity as the temperature of the hot syngas decreased from 1500 °C to 827 °C. The heat in the discharged gas is used to convert 225 MT/day of water to the steam by the heat exchanger H2. The hot steam that comes from heat exchanger H2 drives another stream turbine T3 and generates 1.27 MW of electricity. The total outlet is 40.11 MW of electricity and 880.80 MT/day of syngas which is at 350°C and 1 bar (Table 8). 7.2MW of heat is carried by cooling water in the condensers and will be treated as a source for resident heating source instead of discharging directly into the environment. Considering all the utilities usage and consumed energy in power production, the efficiency of this power generation unit is calculated as 31.24%. According to the data from NETL [44], IGCC power plant with CO2 capture has an efficiency of 32.6% and 31.0% for the GE radiant-only plus quench gasification-based IGCC with carbon capture and E-Gas™ two-stage gasification-based IGCC with carbon capture, respectively.

Figure 12 Block flow diagram of power production unit.

Table 8 Heat streams for power production.

3.5 Water Gas Shift Unit

Using syngas to produce methanol is a traditional method in the chemical industry. However, methanol synthesis needs reactants with a high portion of H2 and a Water-Gas-Shift (WGS) unit can produce H2-rich syngas for methanol production.

The gas mixture coming from coal gasification is injected into the WGS unit. The main components are CO, H2, CO2, and H2O. Other impurities such as waste gas and solid residue are removed in advance in the coal gasification unit. The inlet mixture consists of 416.67 MT/day of CO, 12.74 MT/day of H2, 251.72 MT/day of CO2, 192.20 MT/day of H2O. The process flow diagram and the stream table of WGS unit are shown in Figure A4 and Table A4 within the Appendix.

The hot gas coming from the power production goes to an equilibrium reactor where WGS reaction R14 occurs at 350 oC and 1 bar. [45]

CO + H2O → CO2 + H2 (R14)

R14 is an equilibrium and endothermic reaction. An R-equil reactor is utilized to simulate this process. Conversion of H2 increases as temperature goes up. The utilization of the catalyst is essential for a proper selectivity. Both the high and low temperatures catalysts are available commercially. In this work, the reactions at the WGS occur at 350oC and 1.01 bar and uses Fe3O4/Cr2O3 as the catalyst [45]. At the exit of WGS reactor, 168.45 MT/day of CO, 30.61 MT/day of H2, 641.72 MT/day of CO2 and 32.55 MT/day of H2O are produced. 28.80 MT/day of water is separated by condensing from mixed gas at 5 oC and can be used or sold as cooling water. The rest of the mixture is fed to the carbon capture and sulfur removal unit where the selexol, which is hydrophilic solvent, is used as the solvent.

3.6 Carbon Capture and Sulfur Removal Unit

Carbon capture and sulfur removal in coal-based gasification are called acid gas removal. This operation removes redundant CO2 in the syngas and adjusts the contents of reactants gas for methanol production. It also makes a great contribution to the remission of global warming. How to capture and store carbon from industry-scale fossil power plant is critical. Clarification of carbon path and especially the CO2 path would help to control and therefore reduce the emission.

Figures 13 and 14 show the paths of the carbon and CO2 in the entire process, respectively. The main approaches are pre-combustion CO2 capture, oxy-combustion CO2 capture, and post-combustion CO2 capture. [46] In this study, post-combustion CO2 capture technology is applied and 589.76 MT/day of CO2 is captured, compressed, and transported to a prepared storage site [47].

Selexol is used as a solvent, which is based on poly (ethylene glycol) dimethyl ether (PEGDME) and can efficiently capture CO2 and H2S from lighter gases including H2 [48]. Using a hydrophobic solvent such as PEG-slioxane-1 has an only minimal effect on the cost of carbon capture [49].

Remaining gas mixture containing mainly CO, H2 and CO2 is used as the feedstock for methanol production (see Figure 14).

Figure 13 The pathway of element carbon (C) in the entire process.

Figure 14 The path of carbon dioxide in the entire process with unit of MT (metric tons)/day.

The mixed gas in the inlet of carbon capture and sulfur removal unit consists of 168.45 MT/day of CO, 641.72 MT/day of CO2, 30.61 MT/day of H2, 3.78MT/day of H2S and 3.75MT/day of water. This unit contains two absorbers, one stripper, a three-stage flash system and a condenser. One absorber absorbs H2S by CO2-rich Selexol solvent, while the absorber captures CO2 by lean and semi-lean Selexol [48]. At the same time, a stripper regenerates and recycles Selexol. An H2S condenser concentrates the H2S from a CO2-rich gas by purged air. The stage flash drums regenerate the CO2-rich selexol [49]. 3.78 MT/day of H2S and 589.76MT/day of CO2 is removed from syngas by 4145.61 MT/day selexol. The ratio of H2 to CO of two is attained to produce methanol. Over 92% of CO2 is captured and most of the H2S is removed to guarantee a clean reaction environment for methanol production. Captured CO2 is compressed by the multi-stage compressor to 120 bar, 46oC in the final stage in a liquid phase [50]. Figure 15 shows the block flow diagram of carbon capture and sulfur removal unit. The stream table and process flow diagram are shown in Table A5 and Figure A5, respectively in the Appendix.

Figure 15 Block flow diagram of carbon capture unit. [49]

3.7 Methanol Production

Methanol is emerging as an alternative fuel due to its storage and transportation properties [51]. As the economy develops and industry progresses, the demand and price for global methanol may expand as shown in Figure 16. With over 90 plants worldwide the current production capacity is nearly 100 million metric tons [52-54].

Figure 16 Methanol price and demand in recent history [55, 56, 61].

The demand for methanol is likely to increase by years. Methanol is a valuable chemical which is widely used in different areas. Figure 17 displays the distribution of the use of methanol in 2015. Methanol is a valuable feedstock of producing formaldehyde, acetic acid, biodiesel, and many other chemicals. Methanol is also a valuable solvent in different chemical operations.

Figure 17 Methanol use in 2016 [55]

To produce methanol is becoming another way out for increasing profits and reduce CO2 emission.

Typically, the entire process of methanol production from syngas can be described in four steps: syngas production, syngas reforming, methanol synthesis, and purification. In this work, pre-treated and cleaned syngas is used for methanol production based on the following reactions [56,57].

CO2 + 3H2 → CH3OH + H2O ∆H° (298K)= - 49.4 kJ/mole (R15)

CO + 2H2 → CH3OH ∆H° (298 K) = - 90.55 kJ/mole (R16)

A stoichiometry factor S = (H2-CO2)/ (CO2 + CO) ≈ 2.0 [58] was maintained for a high yield of methanol synthesis. The WGS unit is designed to produce enough hydrogen, while carbon capture and sulfur removal unit is built to remove a certain amount of CO2 and sulfur.

An R-stoic reactor representing the Lurgi reactor [56, 57, 59] is used to simulate the synthesis of methanol at 260 °C and 50 bar. Conversion is high for the overall process using reactions R15 and R16 and a Cu-based catalyst Cu/ZnO/ZrO2 ZnO on an Al2O3 support due to its high selectivity [45, 53, 60]. Based on the literature research, the conversion of CO2 of 98% can be achieved at 260°C and 50 bar, while the conversion of CO in reaction R16 approaches to a peak value of 52% [45]. Figure A6 and Table A6 within the Appendix show the process flow diagram and stream table, respectively for the methanol production. This plant uses 29.89 MT H2/day, 157.17 MT CO/day and 51.96 MT CO2/day, and produces 207.99 MT methanol/day at 99.8 wt% together with 30.59 MT/day of 99% H2O waste water. The RSK thermodynamic model is used. The mixed gas at 134°C and 1 bar is cooled down to 25°C, and compressed into 50 bar. The mixed gas is injected into the main reactor R701. The outlet of the reactor goes into a flash separator after cooled down by another heat exchanger at 70°C. The amount of heat recovered is 5.427 MW and used in the boiler in power production unit to generate steam. The methanol is purified in a distillation column, while the rest of the unreacted mixture is compressed and recycled to the reactor. The column has 20 stages with sieve trays, the feed enters at stage 14. The column has a partial condenser operating at 61.7 °C. A recent publication has indicated that “Methanol production has the potential for the best possible technology deployment ranging from 16% to 35%.” [20, 45, 56] The methanol and water are cooled by the heat exchangers to the storage temperatures. Column specifications and operating conditions are present in Table. 9.

Table 9 Column specifications and results for column in the methanol production [18]

3.8 Results

Several optimization tools of the Aspen Plus package including ‘Energy Analysis’, sensitivity analysis, design specs, and optimization with constraints are applied.

3.8.1 Optimization

Optimization block is based on the objective function for maximized power production (see Figure 12) by varying the recycling water amount under the constraint of the steam temperature. The optimized rate of electricity is eventually achieved as 40.11 MW.

3.8.2 Sustainability

Sustainability analysis helped evaluate the feasibility of the plant. It presents three primary indicators, which are the material indicator, energy indicator, and environment impact indicator. In this analysis, the main sustainability indicators are the usage of nonrenewable material, nonrenewable energy, fresh water, and rate of GHG emissions. The environmental impact indicators are estimated by the Carbon Tracking method based on the CO2e emission factor data source of US-EPA-RULE-E9-57 and the ultimate fuel source of natural gas [18]. Sustainability metrics below are estimated by normalizing the sustainability indicators with respect to the unit amount of production

Material intensity = 𝑁𝑜𝑛𝑟𝑒𝑛𝑒𝑤𝑎𝑏𝑙𝑒 𝑚𝑎𝑡𝑒𝑟𝑖𝑎𝑙 𝑑𝑒𝑝𝑙𝑒𝑡𝑒𝑑 / 𝑈𝑛𝑖𝑡 𝑎𝑚𝑜𝑢𝑛𝑡 𝑜𝑓 𝑝𝑟𝑜𝑑𝑢𝑐𝑡 (3)

Water intensity = 𝐹𝑟𝑒𝑠ℎ𝑤𝑎𝑡𝑒𝑟 𝑑𝑒𝑝𝑙𝑒𝑡𝑒𝑑 / 𝑈𝑛𝑖𝑡 𝑎𝑚𝑜𝑢𝑛𝑡 𝑜𝑓 𝑝𝑟𝑜𝑑𝑢𝑐𝑡 (4)

Energy Intensity = 𝑁𝑜𝑛𝑟𝑒𝑛𝑒𝑤𝑎𝑏𝑙𝑒 𝑒𝑛𝑒𝑟𝑔𝑦 𝑢𝑡𝑖𝑙𝑖𝑧𝑒𝑑 / 𝑈𝑛𝑖𝑡 𝑎𝑚𝑜𝑢𝑛𝑡 𝑜𝑓 𝑝𝑟𝑜𝑑𝑢𝑐𝑡 (5)

Environmental Impact Intensity = 𝐶𝑎𝑟𝑏𝑜𝑛 𝑑𝑖𝑜𝑥𝑖𝑑𝑒 𝑒𝑞𝑢𝑖𝑣𝑎𝑙𝑒𝑛𝑡 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 / 𝑈𝑛𝑖𝑡 𝑎𝑚𝑜𝑢𝑛𝑡 𝑜𝑓 𝑝𝑟𝑜𝑑𝑢𝑐𝑡 (6)

The coal gasification facility consists of an Air Separation Unit (ASU), steam generation unit, coal gasification unit, Water Gas Shift (WGS) unit, carbon capture unit, methanol production and power production unit. Table 10 shows the sustainability indicators of the entire process.

Table 10 Sustainability indicators for integral clean-coal technology with methanol production.

The net stream CO2e and total CO2e are high in this integrated clean-coal technology, mainly due to productions of CH4 and N2O that are intensive GHGs. The total GHG emission is around 847.63 MT/day, of which 207.99 MT/day of CO2e is consumed by methanol production, 589.76 MT/day CO2 is captured liquefied and stored which can be used, for example, in enhanced oil recovery. The integral facility requires 500 MT coal/day, 10 MT H2O/day and 2231.02 MT air/day in total and produces 207.99 MT methanol/day and 40.11 MW of electricity.

Table 11 presents the sustainability metrics in which the integral clean-coal technology power plant is compared with a conventional IGCC power plant of which the capacity is 339MW by utilizing 3020.17 of Powder River Basin as a feedstock [18,32]. Table 11 also compares the syngas- based methanol production in this study with the methanol production using renewable CO2 and H2. [20].

The material intensity metrics show that the integrated clean-coal technology power plant with methanol production requires 0.52 MT coal to generate 1 MWh of electricity and the conventional IGCC power plant requires 0.37 MT coal to generate 1 MWh of electricity. One of the reasons for this difference is due to the different type of coals that the plants utilize. With the different ultimate analysis of the coals, the amounts of the coal and process water required are consequently different from each other. The energy intensities based on the use of natural gas for the utilities, as well as the energy of coal are 50% and 40% higher, respectively in the clean coal technology analyzed in this study. This may be due to the types of the coal used in the processes.

The environmental impact metrics show that the integral clean-coal technology power plant with methanol production produces 0.75 MT CO2e/MWh electricity that corresponds around 60% reduction. Considering the IGCC as the base case, the CO2e emission in the clean-coal plant is lower than the base cases. As expected, methanol production from renewable hydrogen and CO2 can reduce the GHG emission.

Table 11 Sustainability metrics for the integral clean-coal technology with methanol production and IGCC power plant (base case) [16, 18, 20, 65]

3.8.3 Economic Analysis

The economic analysis of the integral clean-coal technology is accomplished by CAPCOST, and present the result by the discounted cash flow diagrams (DCFD). Conventional IGCC may operate longer time, however, considering the catalyst life utilized in the methanol production, the useful life of the entire plant in this work is adjusted into 20 years.

Purchase costs are estimated by the CAPCOST programming [25]. Fixed capital investments (FCI), cost of land and working capital are estimated based on the FCI. Working capital is 20% of the FCI. Chemical Engineering Plant Cost Index (CEPCI-2017) (= 550.1) [26] is updated by 2017. CEPCI is utilized to estimate the costs and capacity by equation 8.

where x is the capacity factor, which is usually assumed to be 0.6 known as the six-tenths rule [25]. The economic analysis applied the Maximum Accelerated Cost Recovery System (MACRS) as the depreciation method with a 10-year of recovery period. According to the DCFD, Net Present Value (NPV), Payback Period (PBP), and Rate of Return (ROR) are calculated and included in the multi- criteria decision matrix as the economic indicators. Table 12 shows the unit costs of various utilities.

Table 12 Unit energy cost for various utilities [18]

At the current capacities, the total capital cost is estimated to US$366.23 million (2016 US$) for the entire integrated clean-coal technology power plant with methanol production. The FCI is US$288.37 million, land cost is US$5.76 million, and the working capital is US$72.09 million. The estimated annual revenue is around US$ 156.75 million. The raw materials are the PRB coal, air, and water. The price of the PRB coal is $11.5/MT [61]. The waste water, nitrogen, steam, surplus oxygen, and captured CO2 are also considered as byproducts besides electricity and methanol. The value of revenue is based on the selling price of all the products [62,63]. Table 13 lists all the economic data.

The DCFD is based on the data given in Table 13. The values of NPV is around US$ 83.37 million, the PBP is around 15.1 years, while ROR is 5.74 and indicate that all the economic criteria are favorable. Figure A7 and Table A7 in the Appendix display the DCFD based on the data with depreciation. Table A8 lists the probable variations of some major economic parameters, while Figure A8 shows the stochastic economic feasibility criteria of NPV, PBP, and ROR in probability densities estimated by the Monte-Carlo simulations. The stochastic economic analysis shows that the plant is also feasible.

Table 13 Economic data applied in CAPCOST [25,64]. The cost values are shown in million (MM)US$ (2016)

3.8.4 Life Cycle Assessment

The Life Cycle Assessments (LCA) of integrated clean coal gasification power plant assesses the energy, water usage, and environmental impacts of the entire plant from cradle to gate. The assessment includes coal mining, transportation, and processing. For the boundary and scope, it is assumed that the lifetime of the entire plant is 20 years, and each year includes a week to allow maintenance. The coal extraction and mining both take place in North Wyoming and was treated to be large-scale underground long wall mining [65]. Transportation method is railroad. Coal travels in a series of trains with a 4400-horsepower diesel engine [66] from the extraction mine to the plant location in North Wyoming. The loss of coal is due to the transportation with fugitive dust emissions. There is no loss of coal during the loading and unloading. The transport distance will be 200 miles. During the entire life cycle, the content of mercury in the coal analysis is about 0.0703 ppm and 2.25 ppm in the fly ash. The impact of mercury in the air emissions is considered [67].

Greenhouse gas emission, water and energy consumptions are estimated and compared with a conventional IGCC plant (NETL IGCC plant) with carbon capture unit [67]. The NETL IGCC plant is a 543-MW facility using Illinois No.6 coal as a feedstock. Selexol is selected as the solvent in carbon capture and sulfur removal in both the base case and this work.

Definition of the Scope

The cradle-to-gate boundary used in this study includes the three stages that are the raw materials acquisition, raw material transportation, and chemical processes Facility as shown in Figure 18.

Figure 18 Life cycle assessment stages of integrated clean-coal technology power plant with methanol. production.

Inventory Analysis and Impact Assessment

The inventory analysis provides a list of inputs and outputs including material and energy consumed. Emissions and environmental impacts are also assessed.

Air Pollutant Emission

Based on the elements that coal contains, the contents of the air pollutant emission discharged during the power plant life cycle are extremely different. Table 14 lists the criteria for air pollutants included in the LCA for integrated clean-coal technology plant with methanol production.

Table 14 Air pollutant emissions from Stage 1, 2 and 3 [18, 65, 67]

Greenhouse Gas Emissions

The CO2 emission caused by this power plant is stored, recycled and utilized. The CO2 emission from the plant is partially used in methanol production and the rest is captured in carbon capture unit (Figure 19). The total CO2e emissions including the utility-based are 1281.79 MT/day. 589.76 MT/day of CO2 was captured in carbon capture unit, while 51.96 MT/day of CO2 is used as the feedstock in methanol production.

Figure 19 The path of CO2e emissions in integrated clean-coal technology power plant with methanol production.

This power plant needs 255.98 MW of utilities purchased from outside, which include cooling water, fired heat, high-pressure steam, low-pressure steam, refrigeration, and electricity. Figure 20 compares the GHG emissions for the integrated clean-coal plant with methanol production and the conventional IGCC per unit product of electricity [67]. Methanol production helps reduce the emissions slightly. Overall emissions in stage 3 are close to each other for both the cases with around 8% of reduction in the clean-coal technology. The improvements in stage 1 and 2 are around 100% in the clean-coal plant and show that the entire integrated clean-coal plant is an environmentally friendly process.

Figure 20 Comparison of GHG emissions in this work and NETL IGCC plant: Stage 1: Raw Material Acquisition, Stage 2: Raw Material Transportation, Stage 3: Chemical Process Facility. [18,65,67]

Water Usage

In stage 1 and stage 2, only consider the water consumption in mining operations. Before the coal is prepared as a feedstock, it needs to be washed for dust suppression mainly using water, storm water, and sanitary water [63]. In stage 2, there is a little water evaporating from the coal and is neglected. Figure 21 shows the water consumption in all the stages in two cases [18, 65]. The total use of water is reduced from 1.91 to 1.41 MT water/MWh electricity representing around 40% decrease.

Figure 21 Water consumption in all the stages in two cases: Stage 1: Raw Material Acquisition, Stage 2: Raw Transportation, Stage 3: Chemical Process Facility [18,65,67].

Energy Consumption

In the energy consumption analysis, several assumptions should be made [65].

The extraction and mining method for bituminous coal are assumed to be similar for both designs.
Coal transportation method is railroad, and the round-trip distance is 220 miles.
The construction of rail line and the train is pre-existing and will consume no additional energy.
Transportation only includes the main rail line between the coal mine to the plant location.
Transportation is diesel powered locomotive transports.
The energy loss in railway’s catenary and electric power plant is not considered.
The utility properties are unified.

In coal mining and transportation (stage 1 and 2), the energy used to drive the equipment and trains are considered. On stages 3, energy consumption includes heating, cooling utilities and electricity used in the entire plant. The integrated clean-coal technology power plant with methanol production is compared with an IGCC (NETL IGCC plant) in Figure 22 that shows the energy consumptions for both the cases [18,60,62,64]. The total energy use increased from 3.74 in the NETL IGCC plant to a total 6.21 in the clean-coal plant representing an increase of around 66%. The production of methanol has a marginal effect on this increase.

Figure 22 Energy consumption in integrated clean-coal technology power plant with methanol production and IGCC Plant (NETL IGCC plant), MWh/MWh electricity. [18,65,67,69]

3.8.5 Feasibility Assessment by a Multi-Criteria Decision Matrix

In the multi-criteria decision matrix, economics and sustainability indicators together are utilized in a qualitative manner for a comprehensive assessment of the feasibility of the cases considered [20, 70]. Table 15 shows the multi-criteria decision matrix, which utilizes ‘+’ and ‘- ‘for the ratings and estimate the number of plus scores, minus scores, the overall total scores and the weighted total scores. The weight factors are decided by all the shareholders based on operation conditions, plant location, energy cost and security needs of a society. The weighted total scores are used to as guidance for comparing and decision making. Sometimes, the weight total scores could be very close to each other, then it will require to evaluate some more indicators to make an informed decision [70]. As Table 15 shows the weighted total scores as +2.9 and -1.5 for the clean-coal plant and NETL IGCC plant, respectively. This implies that clean coal technology with methanol production seems more feasible.

Table 15 Multi-criteria decision matrix for feasibility analysis of integrated clean-coal technology plant with methanol production and the base case [20]

3.9. Conclusions

The raw materials of this work are 10 MT/day of water, 2231.02 MT/day of air and 500 MT/day of coal and the productions are 207.99 MT/day of methanol, 1309.33 MT/day of nitrogen, 62.8 MT/day of water and 40.11MW of electricity. This clean coal technology power plant consists of air separation unit, steam production, coal gasification, water gas shift unit, power production, carbon capture and methanol production process. The estimates show that the total capital cost is US$366.23 million (2016 US$) which includes US$288.37 million of fixed capital investment, US$5.76 million of land cost and US$72.09 million of working capital cost. Based on the current economic data, price of the products, and raw materials, economic analysis estimates the discounted net present value around US$83.37 million, the discounted payback period around 15 years, and the rate of return around 5.74% for a 20-year operation. All the economic indicators look favorable.

Based cases are presented to compare the sustainability metrics of material intensity, energy intensity, and environmental impact intensity with this integral plant. Utilization of coal for power production and methanol production may lead to the decrease in GHG emission by combined cycle, heat integration, and using proper utilities. The use of oxy-combustion, steam production, and recycling of water and available heat streams contribute toward sustainability of the plant. A life cycle assessment of cradle-to-gate is applied to estimate the GHG emissions, water consumption, and energy consumption. The use of captured CO2 in the methanol production decreases the carbon emissions directly and would have a positive impact on the environment and economics. Multi- criteria decision matrix, consisting of economic and sustainability indicators, assesses the feasibility of the entire plant and compares with the base case that is the traditional IGCC power plant. Multi- criteria decision matrix indicates that the integral clean coal plant with methanol production may be feasible. Further work may be needed to decrease the cost and increase the profit by converting CO2 to more valuable chemicals and improve the efficiency of power production. Some solid waste treatments are required to reduce the environmental impacts.

CHAPTER 4 CHEMICAL LOOPING TECHNOLOGY

4.1 Introduction

Chemical looping technology (CLT) is now attracting more and more attention in the research area of carbon capture and utilization. This novel technology is now developed especially for the reduction of the growing CO2 emission. In 2015, carbon dioxide has accounted for 80% of the global greenhouse gas emission in the US (Figure23) [72]. Fossil fuel burning is the main source of the increasing of CO2 emission.

Figure 23 Greenhouse gas emission in the U.S. in 2015 [72]

Chemical looping technique is applied into chemical looping combustion(CLC), chemical looping gasification (CLG) and chemical looping reforming(CLR) with inherent carbon capture with low energy penalty of around $10-50/ton CO2. The captured carbon dioxide is relatively pure and can be used for chemical production. Chemical looping system mainly constitutes three parts; fuel reactor (FR), air reactor (AR) and oxygen carrier (OC). Oxygen carrier (OC) will deliver the oxygen in the air to the fuel reactor (FR) where combustion, gasification, or reforming will occur by the reaction of fuel and transferred oxygen. The transportation between air and fuel using oxygen carrier ensures the fuel only directly contacts with O2, resulting in the nearly pure CO2 in the product gas. Oxygen carrier is a metal oxide (MeO) which is reduced to carry the O2 in the air to the fuel reactor. After the reaction in FR, the reduced OC will be regenerated in the air reactor (AR) by reoxidization. (See Figure 24)

Figure 24 Basic flow diagram of chemical looping system.

This work introduces some backgrounds and basic information of chemical looping technologies and will mainly focus on the coal-based chemical looping systems and the relevant applications. The US holds the largest reserve of 22.1% of total coal by 2016 [73]. Although chemical looping system is not applied at commercial scale, this technique holds great potential in the clean coal technology development [74].

4.2 Chemical looping combustion (CLC)

Fossil fuels and renewable fuels are both suitable for CLC process. In gaseous fuel based combustion process, metal oxide is the ultimate source of oxygen which couples the combustion reaction to the reduction-oxidation loop by equation R17and R18 [70].

The basic cycles of oxidation/reduction of CLC are shown in Figure 25.

Figure 25 A basic chemical looping combustion scheme using metal oxide as OC.

Compared to gaseous fuel, coal requires additional treatment such as gasification which converts coal into the gas phase and reacts with carried oxygen. The entire process in the fuel reactor is derived by R19-R22 [70, 75, 76].

Reactions R19 through R21 gasify the coal while R22 represents the reduction process. The oxygen carrier MeyOx is reduced into MeyOx-1. Then the reduced oxygen carrier is regenerated by the oxidization R24 in air reactor (AR).

According to R17 and R23, the combustion (reduction) in the fuel reactor both rely on the oxygen carried by oxygen carrier rather than air. This makes sure that the outlet streams of fuel reactor only contain CO2 and H2O from which CO2 can be easily captured by condensing the water or steam.

Comparing solid fuels, gaseous fuel is easy to be dealt with in CLC system as it doesn’t produce ash and Char or require additional gasification as the preparation for combustion. Nonetheless, the vast coal supply indicates that it is still considerable to study CLC with solid fuels. Generally, CLC with solid fuels is demonstrated by ex-situ gasification (eG-CLC), in-situ gasification(iG-CLC), and chemical looping with oxygen uncoupling (CLOU). Among these forms of chemical looping combustion, CLOU is a particular scheme of chemical looping as the gaseous O2 is spontaneously released from oxygen carrier in the fuel combustion reactor at a low oxygen partial pressure. Moreover, In CLOU, the reactions in the fuel and air reactor are exothermic in nature [77]. Figure 26 is the typical example of chemical looping combustion using a fluidized rector [76].

Figure 26 Block flow diagramc of the chemical-looping combustion system. [76]

It is worthy to mention that chemical looping combustion is capable of combining with power production and other chemical production. Figure 27 shows utilizing CLC in power production with methanol production. The gaseous outlets from air reactor and fuel reactor are passed to air turbine and CO2 turbine respectively after gas cleaning. Although additional energy will be applied to the compressors and pumps, the utilization of exhaust gas of CLC is a great saving on the fuel energy.

Figure 27 Block flow diagram of chemical-looping combustion combined cycle [76]

Carbon dioxide can be easily captured by a condenser and can be used as the raw material of another chemical production, for example, methanol production. The co-production in chemical looping combustion extremely increases the coefficient of fuel utilization and boosts the profits. A lab-scale coal-based CLC plant is simulated by Aspen Plus and the feasibility can be estimated by Aspen optimization tools and life cycle assessment method.

Figure 28 Block flow diagram of the coal-based CLC plant. [76]

4.3 Chemical looping gasification and reforming

Chemical looping gasification(CLG) and chemical looping reforming(CLR) system are both promising methods developed from chemical looping technique. Both systems convert fuel into available gaseous fuels and valuable chemicals with suitable oxygen carrier. Taking iron-based CLG/CLR system as an example, the reactions can be explained as R25 to R27 [78].

Gasifier and Reducer: Fe2O3 + fuel → Fe/FeO + CO2/H2O (R25)

Oxidizer/Reformer: Fe/FeO + H2O → H2 + Fe3O4 (R26)

Air reactor/Combustor: Fe3O4 + Air → Fe2O3 + Depleted Air (R27)

The suitable oxygen carriers for CLG are iron-based or Ca-based OCs. Taking CLG from coal using iron-based oxygen carrier for example (Figure 29), in syngas chemical looping system, coal is firstly gasified into syngas by the gasification agent which usually comes from the oxygen by ASU. The syngas will be passed into the fuel reactor and converted to CO2 and water. The mixture of CO2 and water carries a large amount of heat and can be used for power production. The oxygen carrier is oxidized and reacts with steam to produce hydrogen in the H2 reactor. The oxidized oxygen carrier is then reduced partially in the combustor; the hot depleted air is used for power production.

Figure 29 Syngas chemical looping coal gasification with iron-based oxygen carrier [78].

Coal-direct chemical looping is another developing method in CLG. As Figure 30 shown, this process feeds the coal directly into the fuel reactor rather than gasifying the coal with additional gasifier or gasification agents. Typically, the coal reacts with iron-based oxygen carrier in the fuel reactor and is converted into CO2 and H2O. The reduced OC (Fe/FeO) is fed into the oxidizer (H2 reactor) where steam from outside reacts with it and produces hydrogen.

Figure 30 Flow diagram of iron-based coal-direct chemical looping gasification. [79]

Co-production is the highlight of chemical looping gasification technique as its direct products such as CO2, H2 or syngas can be used as the reactants in power and chemical production processes.

Chemical looping reforming is a main hydrogen production process. CLR utilizes steam from outside to increase the ratio of hydrogen to increase the yield of H2. Figure 31 presents a combination of the application of CLG and CLR. In addition, this process applies capture carbon to generate methanol. The rational utilization of CO2 and hot gas into methanol and electricity production accomplishes the sustainable and energy-saving process.

Figure 31 Block flow diagram of Fe-based chemical looping steam reforming and gasification systems for methanol, hydrogen and power production.

4.4 Chemical looping technology using natural ores as oxygen carriers

Selection of OCs is important in a CLC process. Given a consideration of good oxygen transportation capacity and minor processing cost, natural ores are becoming great alternative raw materials to produce oxygen carrier in the chemical looping system. Conventional oxygen carrier contains support material and metal oxides as the active component. The support material enhances the stability of OCs and slows down the loss of OC. However, the synthesis of supporting material and metal oxide will increase the cost of chemical looping system. In the case of natural ores, the active and supporting materials are inherently combined. Some supporting materials such as Al2O3, TiO2 and ZrO2 are bound to the metal oxides in the natural ores to sustain natural ores with more stability. Consequently, the utilization of natural ores reduces the cost of CL processes.

Basically, some crucial characteristics must be considered when natural ores are selected as oxygen carriers: the high capacity of transporting oxygen in chemical looping system, be able to react with fuels, stable physical and thermal properties, safe, and be friendly to the environment. Among them, the most important characteristic is the oxygen transportation capacity. Natural ores are classified into different metal-based OCs (the active component) including the iron-based ores, manganese-based ores, copper-based ores and natural gypsum oxygen carriers. The compositions of some common natural ores are listed in Table 16.

Table 16 Natural ores tested as oxygen carrier* [76, 80]

4.4.1 Iron-based ores

Ilmenite is the most common iron-based ores used as OC. The idealized component of Ilmenite is FeTiO3 which can substitute to the titanium supported iron oxides. Minor cost and high crush strength improve the value of them acting as oxygen carriers [81-84]. It is found that Ilmenite performs better on the hydrogen conversion than CO conversion. [84] however, CH4 conversions of ilmenite are observed relatively low in most cases. Table 17 lists the researches for solid fuels using ilmenite in CLC process.

Table 17 Literature results of various tests of ilmenite as an oxygen carrier in chemical looping combustion (Solid fuels only).

4.4.2 Manganese-based ores

Manganese-based ores are widely used as OC materials due to the low price and safe operating conditions. Comparing with iron-based oxygen carrier, they have a larger oxygen carrying capacity. The active component of manganese ores is the oxide form of manganese Mn2O3 and MnO with the

content of 30% to 60% [80]. In the solid fuel based CLC, the fuel conversions are relatively high. Arjamand et al. [92] concluded that the conversion of char can be improved by existing of alkali particles in the ore as a kind of catalyst. Alkali particles create cavities and channels in the fuel and hence increase the contact surface and reaction rate which is up to 4 times as fast as ilmenite. [93]. However, the catalysis impacts will disappear as the alkali is not regenerated and will be lost after multiple redox cycles [94]. On the other hand, Schmitz et al., [95] discovered that the Mn ores can work with low attrition rate, which helps to decrease the number of produced fines. Table 18 presents the cases of CLC using solid fuel with manganese-based ore OCs.

Table 18 Literature results using Mn-based ores as oxygen carriers in solid fuel based CLC.

4.4.3 Copper-based ores

The idealized composition of copper-based ores is normally CuO. Treated CuO releases gaseous oxygen very fast in the fuel combustion reactor. Hence, it results in a high solid fuel conversion and greater fuel efficiencies. Using CuO as oxygen carriers performs well in the stability as the “low melting point agglomeration [80, 97] and sintering is a concern at high temperatures” [97-99]. One way to solve the problem of the agglomeration is to use Cu-based ores alternatively, however, with higher OC loadings [99]. Another issue needs to be dealt with is to reduce the sintering of the ores to avoid the decrease of fuel conversions. Some results of Cu-based ores utilization for solid fuel CLC system from literature researches are displayed in Table 19.

Table 19 A collection of results using copper-based ores as oxygen carriers in CLC. [76,80]

4.4.4 Natural gypsum ores

Natural gypsum ores are becoming more and more popular in the application of oxygen carrier. Gypsum is mainly composed of CaSO4.2H2O and its active compound is mostly CaSO4. Compared with other oxygen carriers, gypsum oxygen carriers perform more environmental-friendly in the oxidized systems [104,105]. The outstanding merit of gypsum ores is the highly active component (CaSO4) content which can achieve 60–70% [80]. Some novel studies are presents by the latest researches. Xiao et al. [106] studied the “reduction kinetics of CaSO4 with CO in a differential fixed bed”. Zheng [107] proposed a coal-based CLC system that used NiO and CaSO4 as oxygen carriers in the interconnected fluidized beds. It has been proved that CaSO4/CaS is an available selection for the oxygen carrier in a CLC system [108,109]. Table 20 shows the literature results of CLC system using gypsum ores.

Table 20 A collection of results using gypsum (CaSO4) as oxygen carriers in solid fuel -based CLC system.

4.4.5 Comparison of Natural Ores with Conventional OC

Natural ores are promising materials in the substitution of conventional oxygen carriers to meet the economic requirements in the chemical looping systems. The abundant resource and minor price increase the study value in the using natural ores as oxygen carriers.

Oxygen transport capacity is the most concerned property to estimate the ability of an oxygen carrier. The oxygen transport capacity (RO2) can be defined by equation R26 [80, 111].

where, 𝑤𝑂𝐶 is the fraction of active material for oxygen carrier. 𝑅𝑂 is called the oxygen transport capability which is defined as equation R27.[80,111]

where mo and mr are the mass of fully oxidized and reduced OC, respectively [72, 80]. Table 21 shows the oxygen transport capability and oxygen transport capacity of some conventional oxygen carriers and natural ores.

Table 21 Oxygen transport capability and theoretical oxygen transport capacities of conventional oxygen carrier and Natural ores. [80]

According to Table 21, most of the oxygen transport capacity of natural ores are not as high as the conventional oxygen carriers. The reduction of the oxygen transport capacity mostly dues to the existing of impurities contained in the natural ores. On the other hand, in view of the costs in the pre-treatment and synthesis of support material and metal oxides, natural ores are still preferential choices to replace the traditional oxygen carriers. It is mentionable that some natural ores usually contain multiple metal oxides. As a result, the total oxygen transport capacity may be increased to a degree. The utilization of mixed natural ores as OCs can be hence applied widely in various chemical looping systems.

4.5 Conclusion

Compared to the traditional electricity generation plants, Chemical Looping System is still a newly- developing industry. It is worth studying when associated with the application of natural ores.

Some techniques such as chemical looping gasification(CLG) and chemical looping reforming (CLR) are the extends of chemical looping principle to concentrate on syngas and hydrogen production as well as electricity production. These methods are able to convert almost any solid and gas fuel into power and chemicals by using cheap and abundant raw materials.

However, some factors prevent chemical looping technologies becoming commercialized in hydrogen production or carbon capture. The stability and properties of oxygen carrier are very important in chemical looping systems. Therefore, the selection of oxygen carriers is a significant consideration in developing of chemical looping system. The metal oxides with great performance have mostly high cost. As a result, using ores as OCs is becoming more and more attractive. The oxygen transport capacity of natural ores may not be as high as conventional OCs’; however, the low cost and abundant resources make them competitive oxygen carriers.

CHAPTER 5 SUMMARY AND CONCLUSIONS

Modern chemical process engineering still pays attention to the development of coal-based energy technologies. Coal is a cheap and abundant energy resource that will not be abandoned in the upcoming decades. To meet the requirements of the concepts of “green chemicals” and improve the energy efficiency, more affordable and clean coal techniques and analysis methods need to be developed. Technologies such as coal gasification, carbon capture and chemical looping systems are proposed to prevent and fix those problems GHG emissions. This work studies the clean coal technologies with coproduction of power and methanol. Air Separation, steam generation, coal gasification, electricity production, water gas shift, carbon capture, methanol production and chemical looping system with natural ores are investigated. Besides the designed chemical processes, sustainability, economic performances and feasibility of the plant are analyzed.

Indicators and metrics are also used to address the extent of sustainability of the entire plant. A cradle-to-gate Life Cycle Assessment is applied to estimate the environment impacts including greenhouse gas emission, water utilized and energy consumption. The combination of these novel technologies strengthens the feasibility of the integral operations.

Coal gasification would prevent the emissions caused by direct combustion. Combined with oxy-combustion, the gasification process ensures the tail gas only contains CO2 and water, which makes the capture of CO2 easy. This work utilizes an oxy-combustion before the coal entering into the gasifier. The goal of this oxy-combustion provides the CO2 required in the following char gasification. The carbon conversion can achieve as high as 99.8%.

The design of IGCC power plant with methanol production converts all the available energy from coal into heat and electricity. Disposed water and wastes are processed in the waste treatment department. The CO2 fixed in the coal is either captured and stored in a storage site or used to produce methanol. It is remarkable that the methanol production makes the entire plant valuable and sustainable as the methanol can be widely used as reactants, fuels, intermediate or solvent.

Operations of methanol will not produce new CO2e emission as it fixes CO2 inherently. The co- production of IGCC power plant increases the revenue and the facility feasibility. Generally speaking, the entire design is sustainable and environmentally friendly.

Chemical looping combustion(CLC), chemical looping gasification (CLG) and chemical looping reforming (CLR) are well-developed techniques. Using ores as oxygen carriers in CLC decreases the cost with a comparable oxygen transfer capacity in the oxidation. CL technique is a promising method for capture carbon in the future.

CHAPTER 6 FUTURE RESEARCH

Great efforts are needed in greenhouse gas control, especially when applying coal as the fuel source. Clean coal technologies are developed to better serve the requirements related to the environmental needs. Given the consideration to economic, environmental and energy saving issues, clean coal technology optimization and investigation are essential. Co-production is a reasonable method to better utilize coal. Future work can be focused on the related chemical production using coal gasification product. A techno-economic analysis coupled with a life cycle assessment of the entire ore production process and use in CLC would be an effective way to investigate the true feasibility of ore use as an OC.

To promote the development of coal energy technology, chemical looping system is brought forward. However, this technique is currently not commercialized due to the circulation of large amounts of oxygen carrier at a high temperatures and high cost of the entire process. Even so, chemical looping is still an ideal substitution for the conventional coal gasification and combustion in power generation and carbon capture. Chemical looping combustion, gasification and reforming processes are able to use to capture carbon dioxide. Using chemical looping technique in conventional coal gasification process and IGCC power plant to substitute carbon capture unit and oxy-combustion is very encouraging. Optimization of the CL system and how to develop it into a commercial scale is the major forecast.

Future work also will keep an eye on the combination of chemical looping systems with other novel techniques. For example, the conjunction of chemical looping and hydrothermal processes is a possible extension of the chemical looping concept as it is capable of converting captured CO2 into formic acid and methanol. Hydrothermal processes are able to convert biomass and CO2 to organic acids, methanol, biocrude and some other valuable chemicals by aqueous chemical reactions under high temperature and pressure conditions [76]. Such a high temperature (around 200 - 350 oC) keeps the water under liquid phase and turns all the hydrogen from water into formic acid. This combined process [116] involves two chemical loops and can convert captured CO2 and glycerin to formic acid and lactic acid using a zero-valent metal as the oxygen carrier. The process scheme is displayed in Figure 32.