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Processes simulation study of coal to methanol based on gasification technology
Abstract
This study presents a simulation model for converting coal to methanol, based on gasification technology with the commercial chemical process simulator, Pro/II ® V8.1.1. The methanol plant consists of air separation unit (ASU), gasification unit, gas clean-up unit, and methanol synthetic unit. The clean syngas is produced with the first three operating units, and the model has been verified with the reference data from United States Environment Protection Agency. The liquid phase methanol (LPMEOH™) process is adopted in the methanol synthetic unit. Clean syngas goes through gas handing section to reach the reaction requirement, reactor loop/catalyst to generate methanol, and methanol distillation to get desired purity over 99.9 wt%. The ratio of the total energy combined with methanol and dimethyl ether to that of feed coal is 78.5% (gross efficiency). The net efficiency is 64.2% with the internal power consumption taken into account, based on the assumption that the efficiency of electricity generation is 40%.
... The National Institution for Transforming India (NITI Ayog) has launched the "Methanol Economy" mission to meet future energy demand, reduce oil imports, and GHG emissions. Methanol can be produced from high-ash coal, low-value agricultural biomass residue, municipal solid waste, domestic waste, CO 2 from thermal power plants, and natural gas [8][9][10]. Methanol has higher autoignition temperature, octane number, flame speed, and flammability limits than baseline gasoline. ...
This study investigated the effect of the methanol–gasoline blend (M15) on the combustion and performance characteristics of a commercial light-duty Bharat Stage-VI (BS-VI) 2020 spark-ignition (SI) engine. The M15 and baseline gasoline (G100) engine tests were performed at a wide range of engine loads and speeds. For the M15 operation, it was ensured that the lambda values matched with the baseline gasoline operation at each engine operating point by changing fuel quantity manually. The combustion characteristics of M15 were quite similar to gasoline at all operating points. Alcohol addition improves octane number and flame speed, which changes the combustion characteristics of the engine, but in this study, the combustion characteristics of M15 fuel were almost identical. It may be due to blending a small fraction of methanol and the engine's high compression ratio, which improved the combustion kinetics. The coefficient of variance of indicated mean effective pressure was slightly lower for M15 than gasoline, except at 1000 rpm, where the charge mixing might not be adequate at low engine speed for M15 due to lower methanol volatility. Engine's brake thermal efficiency improved with M15 fueling by ∼1%, compared to baseline gasoline, though brake-specific fuel consumption deteriorated by ∼6% due to the lower calorific value of M15. Higher combustion stability and possibly lower heat transfer losses, as observed from slightly higher exhaust gas temperature (EGT), might have improved the engine's performance for M15. This study demonstrated that M15 fueling exhibited identical combustion characteristics and higher thermal efficiency than baseline gasoline fueling at similar lambda values in a commercial light-duty BS-VI SI engine.
... Chen et al. [27] performed a simulation model for converting coal to methanol based on gasification technology with the commercial chemical process simulator. The methanol plant consisted of air separation unit, gasification unit, gas clean-up unit, and methanol synthetic unit. ...
Methanol is an alternative, renewable, environmentally and economically attractive fuel, considered to be one of the most favorable alternative fuels to conventional fossil-based fuels. Nowadays, in order to meet the various emission regulations and improve the atmospheric environment, methanol fuel has been used as a clean fuel to replace conventional fuels for the internal combustion (IC) engine. Compared with the conventional fossil-based fuels such as gasoline, methanol has better fuel conversion efficiencies due to larger vaporization heat and much better resistance to knock. Because of a large number of studies and applications that have been ongoing recently, much progress has been made that is worth reporting. This chapter systematically describes the applications such as methanol-gasoline, methanol-diesel, or other blends that can be used in the IC engines. Finally, it puts forward some new suggestions on the weakness in the studies of methanol or methanol-blends engines.
... The combination of a gasifier and a combined cycle is called the Integrated Gasification Combined Cycle. The multitude applications of syngas can be shown in figure 1 [17]. Energy and exergy analysis of gasification performed for obtaining performance and irreversibility's of the process [18]. ...
Cryogenic air separation plants are used for production of oxygen with purity over 99.99% (first grade oxygen) as required for welding, cutting, and medical applications. These plants are operates at low thermodynamic efficiency with specific power consumption in a range between 0.5-0.6 kwh/scmh of O 2. Medium purity cryogenic air separation units (ASU) are chiefly required for gasification. As air gasification produces poor quality syngas, oxygen is used as gasifying agent for biomass gasification. Biomass gasification with oxygen as gasifying agent has great potential in applications like integrated gasification combined cycle (IGCC), chemical production and Fischer-Tropsch (F-T) products. In this work simulation of medium purity oxygen cryogenic air separation plant integrated with biomass gasifier is carried out by using Aspen plus. Such cryogenic air separation plants which produce oxygen in a range between 85-98% can be used economically for gasification. The cryogenic oxygen plant produces oxygen with purity 96.2 % mole basis with specific power consumption as 0.2435 kw/scmh of O 2. The performance parameters like recovery, purity, temperature and pressure and power consumption of cryogenic air separation unit are obtained. The parameters like syngas composition and heating value also predicted in simulation of biomass gasifier.
... Chen et al. [27] performed a simulation model for converting coal to methanol based on gasification technology with the commercial chemical process simulator. The methanol plant consisted of air separation unit, gasification unit, gas clean-up unit, and methanol synthetic unit. ...
... The combination of a gasifier and a combined cycle is called the IGCC. Including IGCC, other different applications where syngas can be used are highlighted in (Chen et al., 2010). The multitude applications of syngas can be shown in Figure 1. ...
Cryogenic air separation plants are used for production of oxygen, nitrogen and argon with required purity and recovery.The first grade oxygen (purity over 99.99%) is required for welding, cutting, and medical applications. These plants operate at low thermodynamic efficiency with specific power consumption in a range between 0.5-0.6 kw/scmh of O2. As air gasification produces poor quality syngas, oxygen is used as gasifying agent for biomass gasification. Medium purity cryogenic air separation units (ASU) are chiefly required for gasification. Biomass gasification with oxygen as gasifying agent has great potential in applications like integrated gasification combined cycle (IGCC), chemical production and Fischer-Tropsch (F-T) products. In this work simulation of medium purity oxygen cryogenic air separation plant integrated with biomass gasifier is carried out by using Aspen plus. Such cryogenic air separation plants which produce oxygen in a range between 85-98% can be used economically for gasification. The cryogenic oxygen plant produces oxygen with purity 96.2 % mole basis with specific power consumption as 0.2435 kw/scmh of O2. The performance parameters like recovery, purity, temperature and pressure and power consumption of cryogenic air separation unit are obtained. The parameters like syngas composition and heating value also predicted in simulation of biomass gasifier. The effect of parameters (parametric analysis), like vapour fraction of the feed on pure liquid (PL) flow and condenser duty, effect of number of stages on PL and rich liquid (RL) flow and its purity and effect of oxygen flow and gasifier temperature on syngas composition is discussed.
... Syngas produced by oxygen or steam gasification is having higher heating value than the syngas of air gasification process. This syngas produced by oxygen and steam gasification is also having composition suitable for chemical production like Methanol [9]. ...
In today`s scenario of depleting conventional fossil fuels biomass provides an alternate source of energy. Gasification is a chemical process that converts carbonaceous materials like biomass into useful convenient gaseous fuels or chemical feedstock. The gasification process uses an agent air or oxygen, hydrogen or steam to convert carbonaceous materials into gaseous products. As air gasification produces poor quality syngas, oxygen is used as gasifying agent for biomass gasification. Biomass gasification with oxygen as gasifying agent has great potential in applications like IGCC (Integrated Gasification combined cycle), Chemical Production and Fischer-tropsch products. In this paper the simulation model of a biomass gasifier for different biomass like charcoal, rice husk and wood pellets with oxygen and air as a gasifying agent is developed using ASPEN Plus. The model predicts syngas composition, heating value, temperature, pressure and quantity of gas produced. These results are obtained for various feedstocks like wood pallets, rice husk, and Indian coal on the basis of proximate and ultimate analysis.
... Efficiency GTL plants: 60% [194][195][209] Efficiency CTL plants: 49% [195] Efficiency CTM plants: 55% [210][211] Efficiency CSNG plants: 60% (LHV based) [197][212] Efficiency IGCC plants: 42% [161][165] A. ...
In this work, an economic assessment of large-scale production of Synthetic Natural Gas from biomass (bioSNG) has been carried out. With the aim of estimating the total capital investment of a large-scale bioSNG facility, different commercial plants based on gasification technology, including Gas-to-Liquids (GTL), Coal-to-Liquids (CTL), Coal-to-methanol (CTM), Coal-to-SNG (CSNG), and Integrated Gasification Combined Cycle (IGCC) have been used as references. The layout for SNG production from biomass is based on MILENA indirect gasification (technology developed by ECN). The average Total Capital Investment (TCI) for a large bioSNG plant (1 GW thermal input) has been determined as ~1530 USD2013/kWinput. Technology learning could further decrease the TCI of a bioSNG plant with about 30% to 1100 USD2013/kWinput after a cumulative number of 10 GW installed capacity. A TCI of 1100 USD2013/kWinput results in an overall bioSNG cost price of 14-24 USD2013/GJ, largely depending on the price of biomass feedstock. From three scenarios considered (wood chips in Europe and United States, or cheap agricultural residues from Brazil/India), the latter is the best in terms of cost price of SNG. However, Europe offers several advantages for the deployment of SNG from biomass, e.g. existing natural gas infrastructure, and an existing SNG market based on incentives and obligations. Internalization of CO2 emissions in the 2030 untaxed price of SNG reveals that bioSNG can be competitive with SNG produced from coal, with a cost of 25 USD2013/GJ. Even so, medium-term bioSNG prices are expected to remain higher than future natural gas prices. However, the implementation of concepts such as the co-production of bioSNG/bioLNG and chemicals/biofuels, the capture and storage of CO2, or power-to-gas systems will contribute to enhance the business case of bioSNG production. ECN is working on all these topics.
Methanol-to-gasoline (MTG) process is a sustainable approach for producing gasoline-range hydrocarbon biofuels. It can also mitigate the challenges associated with crude oil, such as environmental pollution, scarcity and cost of fossil-derived fuels, and political instability in major crude oil-producing countries. MTG process starts with the production of syngas, followed by conversion of syngas to methanol and production of gasoline from methanol. This chapter summarized the various feedstock used for producing methanol, including biomass and carbon dioxide. MTG process started way back in 1978 when the first plant was installed in New Zealand. Since then, significant technological advancement has been witnessed in the MTG process. This chapter thus presents progress in the MTG process. Specifically, the effect of characteristic features of zeolites and various process variables on the MTG process are elaborated. The reaction mechanism and industrial processes are also discussed briefly.
Biorefinery explores the conversion of different biomass into a variety of bio-based products. The bioeconomy is an important aspect of biorefinery. Among various biorefinery concepts, hydrocarbon biorefinery is extremely important and provides hydrocarbon biofuels, which are compatible with the existing petroleum facilities. The techno-economic assessment is useful tool to optimize and improve various biomass conversion processes for the sustainability of hydrocarbon biorefinery. This chapter thus discusses the technical and economic aspects to produce hydrocarbon biofuels using thermochemical conversion pathways of pyrolysis and hydrothermal liquefaction. These pathways produce renewable liquid hydrocarbon biofuels with a minimum selling price in the range of $0.5–3.5/L which is higher in comparison to fossil fuel-based transportation fuels. Thus, to compete with fossil fuels, further improvement in the area of process integration and intensification in hydrocarbon biorefinery is required.
Twin-spark plug synchronous ignition is an effective means of improving the stability of combustion and extending the lean-burn limit of the spark ignition engine. In this study, the distribution of mixture concentration, combustion, and emissions-related behaviors of a direct-injection twin-spark plug synchronous ignition methanol engine are numerically investigated to assess its lean-burn performance and solve for stable combustion under a medium compression ratio. The simulation results shows that the timing of the injection and ignition, and the distribution of flow velocity at ignition determine the distribution of the mixture concentration in the cylinder, which in turn affects the density of the flame surface and emissions. The delay ignition timing, the unburned methanol emissions increase significantly, while the nitrogen oxides emissions decrease rapidly. Optimal injection timing of 110°crank angle before top dead center and ignition timing of 21°crank angle before top dead center could obtain the best compromise of a medium compression ratio direct-injection twin-spark plug synchronous ignition methanol engine under steady-state lean-burn conditions. Thus, twin-spark plug synchronous ignition can ensure stable combustion and yield good performance with a medium compression ratio under lean-burn conditions.
The cold-start mixture preparation, combustion and emissions behaviors of a medium compression ratio direct-injection twin-spark plug synchronous ignition engine fueled with methanol were numerically simulated. Simulation results display that the methanol injection timing, ignition timing and the global equivalence ratio had an important influence on the concentration distribution of methanol-air mixture, the flow velocity, and the density of the flame surface during cold start. Ignition delay period reached the shortest at injection timing 70°CA BTDC. Ignition delay period for injection timing 130°CA BTDC and 50°CA BTDC increased 209% and 45.5% compared to injection timing 70°CA BTDC, respectively. Ignition delay period reached the shortest at ignition timing 21°CA BTDC. Ignition delay period of twin-spark plug was shorter than that of single-spark plug at the same equivalence ratio. There existed the maximum in-cylinder pressure, maximum heat release rate, maximum in-cylinder temperature, lowest unburned methanol and soot emissions, and highest NOX emissions at injection timing 70°CA BTDC. The maximum in-cylinder pressure, maximum heat release rate, and maximum in-cylinder temperature gradually increased with the advance of ignition timing. Injection timing 70°CA BTDC, ignition timing 21°CA BTDC, and equivalence ratio 0.9 could obtain the best cold start performance compromise using twin-spark plug ignition mode. At equivalence ratio 1.0, twin-spark plug ignition had better combustion performances, lower unburned methanol and soot emissions, and higher NOX emissions compared with single-spark plug ignition. Twin-spark plug synchronous ignition had more advantageous to cold starting ignition compared with single-spark plug ignition for a medium compression ratio direct-injection spark-ignition methanol engine.
The effects of twin-spark plug arrangement on flame, combustion and emissions of a medium compression ratio direct injection methanol engine were numerically investigated. Computational results showed that at approximately A (ratio of distance of twin-spark plug and cylinder diameter) = 0.65, the burning and exothermic were the most reasonable compared to other twin-spark plug locations. A = 1.00 was the worst twin-spark plug arrangement. The maximum in-cylinder pressure and the maximum in-cylinder temperature were decreased with increasing A. Ignition delay were increased with increasing A. The A = 0.65 had the shortest combustion duration and the maximum heat release rate. The maximum in-cylinder pressure of A = 1.00 was approximately 57.5% lower than A = 0.25. The ignition delay of A = 1.00 was approximately 2.4 times longer than A = 0.25. The combustion duration of A = 0.67 was approximately 12% and 52.2% lower than A = 0.25 and A = 1.00, respectively. Unburned methanol and soot were increased gradually with increasing A, and at the A > 0.75, the unburned methanol and soot emissions were increased rapidly as increasing A. The unburned methanol of A = 1.00 was approximately 4.6 times higher than A = 0.25. The variations in emitted NOX emissions showed opposite tendencies with the variations in unburned methanol and soot emissions. The optimum arrangement of the twin-spark plug for application of actual engine was approximately A = 0.65.
CO2 utilization via methanol synthesis can be an effective approach to mitigate the issue of global warming. This study developed an innovative process to produce methanol by combining water electrolysis with tri-reforming of methane (TRM). The proposed design utilized carbon-free electricity to split water into O2 and H2; O2 is collected for partial oxidation reaction in the TRM and H2 is collected for stoichiometric number (SN) optimization. This process configuration eliminates the typical problems of H2 surplus or deficit associated with methanol synthesis and allows a substantial amount of CO2 to be converted. The main process flowsheet was developed with Aspen HYSYS process simulator and then the feasibility of this project was evaluated based on its technical, environmental, and economic performances. The estimated capital expenditure (CAPEX), operating expenditure (OPEX) and GHG emissions of the baseline plant are US$774 million, US$263 million/yr. and −0.14 kgCO2eq/kgMeOH, respectively. In particular, water electrolysis process accounted for 34 % of CAPEX and 51 % of OPEX. A discounted cash flow (DCF) model combined with sensitivity analyses showed that a breakeven point could be reached with a methanol price of US$491/ton. The results demonstrated that combining water electrolysis with TRM could achieve a sustainable carbon-sink process for methanol production.
This study proposes an innovative methanol production process from landfill gas (LFG) through direct CO2 hydrogenation and methane (CH4) reforming. The integration of two methanol production routes from CO2 and CH4 enables the full upcycling of carbon sources in the LFG into methanol, as compared to conventional processes that utilize only CH4 as a carbon source. The optimal process configurations and operating conditions of two LFG-to-methanol processes (L2M), stand-alone (L2M-SA) and with hydrogen supply (L2M − HS), are proposed by developing rigorous process models with the aid of sequential quadratic programming optimization. The capability of the processes is analyzed using four evaluation metrics: carbon and energy efficiencies, net CO2 emission, and unit production cost (UPC). It was observed that the carbon and energy efficiencies of both the L2M processes could reach up to 92% and 69%, respectively. The methanol UPC is estimated in the range of 392–440 USD/ton, which is competitive against other renewable and conventional methanol production options. In addition, the CO2 emission (0.83 and 1.29 kg of CO2 per kg of MeOH of the L2M − HS and -SA, respectively) implies that the full upcycling of LFG to methanol is not only economically viable but also an environmentally clean strategy.
In this paper, an exergetic evaluation was conducted on a two-step biomass-derived light olefins system established using ASPEN PLUS. This system linked methanol synthesis via entrained-flow gasification to a methanol-to-olefins (MTO) process. The mass yield of the system was 0.248 kg light olefins per kg biomass, which is relatively higher than the literature results. The energetic and exergetic efficiencies of this system were 54.66% and 47.65%, respectively. The results of an exergetic analysis indicate that the biomass gasification, steam cycle, methanol separation, CO2 removal and olefins separation produce most of the system inefficiencies. By identifying the occurrence mechanism of the exergy losses, the potential for improvement can be obtained. A further increase of exergetic performance can be obtained from (1) improvement of gasification process via combining biomass torrefaction, and (2) enhancement of energy integration processes via heat network optimization and power generation from the produced steam.
In this study, the commercial chemical process simulator, PRO/II (R) V8.1.1, is implemented to perform the simulation of a coal gasification-based co-production system, of which the feedstock is kaltim prima coal from Indonesia, and the products are electricity and dimethyl ether (DME). There are five major blocks in the multi-product plant, i.e. air separation unit (ASU), gasification unit, gas clean-up unit, combined-cycle, and DME synthetic unit. ASU utilizes cryogenic air separation process, which provides oxygen with 95 mol% purity to the gasification unit and nitrogen to the combined-cycle. General Electric technologies are employed in the study, i.e. quench-type slurry-fed gasifier for the former and 7FB-series turboset for the latter. The clean-up unit includes dry solids removal, syngas scrubbing, sulfur compounds removal, and sulfur recovery processes, which are implemented to deliver clean syngas to further processes and elemental sulfur from H2S. The clean syngas is divided into two equal streams to generate electricity and produce DME, simultaneously. The results show that the gross and net electrical power outputs are 371.6 and 275.1?MW, respectively; furthermore, the yield of DME is 51.78 mt/h. In summary, the net efficiency of the coal gasification-based multi-product plant is 46.1% (HHV), which is higher than the counterpart of typical integrated gasification combined-cycle plants by over four percentage points. (c) 2012 Curtin University of Technology and John Wiley & Sons, Ltd.
Methanol is commonly considered a hydrogen source and/or hydrogen carrier. In fact, methanol can be produced by partial oxidation of biomass and in this case it is considered a source for hydrogen and therefore for energy. It can also be produced from carbon dioxide and hydrogen; in this case, it can be seen as a hydrogen carrier because it is easier to transport and store than hydrogen. This work gives an overview of methanol production and use both for hydrogen production and as a feed to fuel cells. Different processes for the production and reactions of methanol are reported, with particular regard to the membrane processes that produce methanol and simplify methanol reactions with respect to traditional systems.
The removal of COS from natural gas is an area of increasing interest in natural gas sweetening, in view of tightening sulfur specifications. In an attempt to improve the absorption of COS in aqueous methyldiethanolamine (MDEA) solutions, the addition of polyhydroxyalcohols (PHA) was studied in small-scale laboratory tests. The addition of 25—30 wt.% ethylene glycol or glycerol increased the reaction rate by a factor up to 5–10, depending on the solvent loading and MDEA concentration. However, pilot plant studies revealed that the COS absorption could not be improved, or even worsened, under practical absorbing conditions. This is attributed to increased solvent viscosity which counteracts the increased reaction rate. The selectivity with respect to CO2 absorption improved, however, in some cases by up to a factor of two.
The aim of this study was to conduct a preliminary feasibility assessment of gasification of New Zealand (NZ) lignite and sub-bituminous coals, using a commercial simulation tool. Gasification of these coals was simulated in an integrated gasification combined cycle (IGCC) application and associated preliminary economics compared. A simple method of coal characterization was developed for simulation purposes. The carbon, hydrogen, and oxygen content of the coal was represented by a three component vapor solid system of carbon, methane, and water, the composition of which was derived from proximate analysis data on fixed carbon and volatile matter, and the gross calorific value, both on a dry, ash free basis. The gasification process was modeled using Gibb’s free energy minimization. Data from the U.S. Department of Energy’s Shell Gasifier base cases using Illinios No. 6 coal was used to verify both the gasifier and the IGCC flowsheet models. The H:C and O:C ratios of the NZ coals were adjusted until the simulated gasifier output composition and temperature matched the values with the base case. The IGCC power output and other key operating variables such as gas turbine inlet and exhaust temperatures were kept constant for study of comparative economics. The results indicated that 16% more lignite than sub-bituminous coal was required. This translated into the requirement of a larger gasifier and air separation unit, but smaller gas and steam turbines were required. The gasifier was the largest sole contributor (30%) to the estimated capital cost of the IGCC plant. The overall cost differential associated with the processing of lignite versus processing sub-bituminous coal was estimated to be of the order of NZ $0.8/tonne.