A system performance and economics analysis of IGCC with supercritical steam bottom cycle supplied with varying blends of coal and biomass feedstock

In recent years, Integrated Gasification Combined Cycle Technology (IGCC) has been gaining popularity for use in clean coal power operations with carbon capture and sequestration. Great efforts have been continuously spent on investigating ways to improve the efficiency and further reduce the greenhouse gas emissions of such plants. This study focuses on investigating two approaches to achieve these goals. First, replace the traditional subcritical Rankine cycle portion of the overall plant with a supercritical steam cycle. Second, add biomass as co‐feedstock to reduce carbon footprint as well as SO_x and NO_x emissions. In fact, plants that use biomass alone can be carbon neutral and even become carbon negative if CO₂ is captured. Due to a limited supply of feedstock, biomass plants are usually small, which results in higher capital and production costs. In addition, biomass can only be obtained at specific times in the year, resulting in fairly low capacity factors. Considering these challenges, it is more economically attractive and less technically challenging to co‐gasify biomass wastes with coal. The results show that for supercritical IGCC, the net efficiency increases with increased biomass in all cases. For both subcritical and supercritical cases, the efficiency increases from 0% to 10% (wt.) biomass and decreases thereafter. However, the efficiency of the blended cases always remains higher than that of the pure‐coal baseline cases. The emissions (NO_x, SO_x, and effective CO₂) and the capital costs decrease as biomass ratio (BMR) increases, but the cost of electricity (CoE) increases with BMR due to the high cost of the biomass used. Finally, implementing a supercritical steam cycle is shown to increase the net plant output power by 13% and the thermal efficiency by about 1.6 percentage points (or 4.56%) with a 6.7% reduction in capital cost, and a 3.5% decrease in CoE. Copyright © 2013 John Wiley & Sons, Ltd.     

Parametric techno‐economic studies of coal/biomass co‐gasification for IGCC plants with carbon capture using various coal ranks,fuel‐feeding schemes,and syngas cooling methods

Because of biomass's limited supply (as well as other issues involving its feeding and transportation), pure biomass plants tend to be small, which results in high production and capital costs (per unit power output) compared with much larger coal plants. Thus, it is more economically attractive to co‐gasify biomass with coal. Biomass can also make an existing plant carbon‐neutral or even carbon‐negative if enough carbon dioxide is captured and sequestered (CCS). As a part of a series of studies examining the thermal and economic impact of different design implementations for an integrated gasification combined cycle (IGCC) plant fed with blended coal and biomass, this paper focuses on investigating various parameters, including radiant cooling versus syngas quenching, dry‐fed versus slurry‐fed gasification (particularly in relation to sour‐shift and sweet‐shift carbon capture systems), oxygen‐blown versus air‐blown gasifiers, low‐rank coals versus high‐rank coals, and options for using syngas or alternative fuels in the duct burner for the heat recovery steam generator (HRSG) to achieve the desired steam turbine inlet temperature. Using the commercial software, Thermoflow^®, the case studies were performed on a simulated 250‐MW coal IGCC plant located near New Orleans, Louisiana, and the coal was co‐fed with biomass using ratios ranging from 10% to 30% by weight. Using 2011 dollars as a basis for economic analysis, the results show that syngas coolers are more efficient than quench systems (by 5.5 percentage points), but are also more expensive (by $500/kW and 0.6 cents/kW h). For the feeding system, dry‐fed is more efficient than slurry‐fed (by 2.2–2.5 points) and less expensive (by $200/kW and 0.5 cents/kW h). Sour‐shift CCS is both more efficient (by 3 percentage points) and cheaper (by $600/kW or 1.5 cents/kW h) than sweet‐shift CCS. Higher‐ranked coals are more efficient than lower‐ranked coals (2.8 points without biomass, or 1.5 points with biomass) and have lower capital cost (by $600/kW without using biomass, or $400/kW with biomass). Finally, plants with biomass and low‐rank coal feedstock are both more efficient and have lower costs than those with pure coal: just 10% biomass seems to increase the efficiency by 0.7 points and reduce costs by $400/kW and 0.3 cents/kW h. However, for high‐rank coals, this trend is different: the efficiency decreases by 0.7 points, and the cost of electricity increases by 0.1 cents/kW h, but capital costs still decrease by about $160/kW. Copyright © 2016 John Wiley & Sons, Ltd.     

Engineering economic analysis of biomass IGCC with carbon capture and storage

Integration of biomass energy technologies with carbon capture and sequestration could yield useful energy products and negative net atmospheric carbon emissions. We survey the methods of integrating biomass technologies with carbon dioxide capture, and model an IGCC electric power system in detail. Our engineering process model, based on analysis and operational results of the Battelle/Future Energy Resources Corporation gasifier technology, integrates gasification, syngas conditioning, and carbon capture with a combined cycle gas turbine to generate electricity with negative net carbon emissions. Our baseline system has a net generation of 123 MW_e, 28% thermal efficiency, 44% carbon capture efficiency, and specific capital cost of 1,730 $ kW_e⁻¹. Economic analysis suggests this technology could be roughly cost competitive with more conventional methods of achieving deep reductions in CO₂ emissions from electric power. The potential to generate negative emissions could provide cost-effective emissions offsets for sources where direct mitigation is expected to be difficult, and will be increasingly important as mitigation targets become more stringent.     

Steam co‐gasification of iron‐loaded biochar and low‐rank coal

Steam co‐gasification of iron catalyst‐loaded biochar, which was produced by the pyrolysis of woody biomass and Indonesian Adaro subbituminous coal at 800 °C, was carried out in this study. The main purpose of this work was to examine the effectiveness of an iron catalyst loaded on biochar for hydrogen (H₂) evolution. It was shown that the H₂ evolution for a mixed sample of iron‐loaded biochar (20 wt%) and Indonesian Adaro subbituminous coal increased by 20% compared with that for the coal sample with the same amount of iron catalyst and was approximately 1.5 that for the coal sample without the iron catalyst. This increase in the co‐gasification H₂ evolution was explained by the chemical form and crystallite size of the iron catalyst. Copyright © 2016 John Wiley & Sons, Ltd.     

Novel hydrogen‐rich gas production by steam gasification of biomass in a research‐scale rotary tubular helical coil gasifier

The concept of biomass steam gasification offers platform for production (i) of hydrogen, (ii) hydrocarbons and (iii) value added chemicals. Majority of these developments are either in nascent or in pilot/demonstration stage. In this context, there exists potential for hydrogen production via biomass steam gasification. Gaseous products of biomass steam gasification consist of large percentage of CO, CH₄ and other hydrocarbons, which can be converted to hydrogen through water‐gas‐shift reaction, steam reforming and cracking respectively. Although there are many previous research works showing the potential of production of hydrogen from biomass in a two stage process, challenges remain in extended biomass and char gasification so as to reduce the amount of carbon in the residual char as well as improve conversion of heavy hydrocarbon condensates to hydrogen rich gas. In the current work, the characteristics of biomass steam gasification in an in‐house designed rotary tubular helical coil reactor at temperatures less than 850 °C, in the presence of superheated steam, were presented. The objectives were to obtain high carbon conversion in the primary biomass steam gasification step (upstream) and high product gas yield and hydrogen yield in the secondary fixed bed catalytic step (downstream). The influence of temperature, steam‐to‐biomass ratio and residence time on product gas yield in the rotary tubular helical coil gasifier was studied in detail using one of the abundantly available biomass sources in India‐rice husk. Further, enhancement of product gas yield and hydrogen yield in a fixed bed catalytic converter was studied and optimized. In the integrated pathway, a maximum gas yield of 1.92 Nm³/kg moisture‐free biomass was obtained at a carbon conversion efficiency of 92%. The maximum hydrogen purity achieved under steady state conditions was 53% by volume with a hydrogen yield of 91.5 g/kg of moisture‐free biomass. This study substantiates overall feasibility of production of high value hydrogen from locally available biomass by superheated steam gasification followed by catalytic conversion. Copyright © 2016 John Wiley & Sons, Ltd.     

A comprehensive techno‐economic analysis method for power generation systems with CO2 capture

A new comprehensive techno‐economic analysis method for power generation systems with CO₂ capture is proposed in this paper. The correlative relationship between the efficiency penalty, investment increment, and CO₂ avoidance cost is established. Through theoretical derivation, typical system analysis, and variation trends investigation, the mutual influence between technical and economic factors and their impacts on the CO₂ avoidance cost are studied. At the same time, the important role that system integration plays in CO₂ avoidance is investigated based on the analysis of a novel partial gasification CO₂ recovery system. The results reveal that for the power generation systems with CO₂ capture, the efficiency penalty not only affects the costs on fuel, but the incremental investment cost for CO₂ capture (U.S.$ kW⁻¹) as well. Consequently, it will have a decisive impact on the CO₂ avoidance cost. Therefore, the added attention should be paid to improve the technical performance in order to reduce the efficiency penalty in energy system with CO₂ capture and storage. Additionally, the system integration may not only decrease the efficiency penalty, but also simplify the system structure and keep the investment increment at a low level, and thereby it reduces the CO₂ avoidance cost significantly. For example, for the novel partial gasification CO₂ recovery system, owing to system integration, its efficiency can reach 42.2%, with 70% of CO₂ capture, and its investment cost is only 87$ kW⁻¹ higher than that of the reference IGCC system, thereby the CO₂ avoidance cost is only 6.23$ t⁻¹ CO₂. The obtained results provide a comprehensive technical–economical analysis method for energy systems with CO₂ capture useful for reducing the avoidance costs. Copyright © 2009 John Wiley & Sons, Ltd.     

Hydrogen and power co-generation based on coal and biomass/solid wastes co-gasification with carbon capture and storage

This paper investigates the potential use of renewable energy sources (various sorts of biomass) and solid wastes (municipal wastes, sewage sludge, meat and bone meal etc.) in a co-gasification process with coal to co-generate hydrogen and electricity with carbon capture and storage (CCS). The paper underlines one of the main advantages of gasification technology, namely the possibility to process lower grade fuels (lower grade coals, renewable energy sources, solid wastes etc.), which are more widely available than the high grade coals normally used in normal power plants, this fact contributing to the improvement of energy security supply. Based on a proposed plant concept that generates 400–500 MW net electricity with a flexible output of 0–200 MW_th hydrogen and a carbon capture rate of at least 90%, the paper develops fuel selection criteria for coal blending with various alternative fuels for optimizing plant performance e.g. oxygen consumption, cold gas efficiency, hydrogen production and overall energy efficiency. The key plant performance indicators were calculated for a number of case studies through process flow simulations (ChemCAD).     

Co‐gasification performance of coal and petroleum coke blends in a pilot‐scale pressurized entrained‐flow gasifier

Co‐gasification performance of coal and petroleum coke (petcoke) blends in a pilot‐scale pressurized entrained‐flow gasifier was studied experimentally. Two different coals, including a subbituminous coal (Coal A) and a bituminous coal (Coal B), individually blended with a petcoke in the gasifier were considered. The experimental results suggested that, when the petcoke was mixed with Coal A over 70%, the slagging problem, which could shorten the operational period due to high ash content in the coal, was improved. It was found that increasing O₂/C tended to decrease the syngas concentration and better operational conditions of O₂/C were between 0.6 and 0.65 Nm³ kg^?1. For the blends of Coal B and the petcoke, the slagging problem was encountered no more, as a result of low ash content in both Coal B and the petcoke. The better co‐gasification performance could be achieved if the blending ratio of the two fuels was 50%, perhaps resulting from the synergistic effect of the blends. With the aforementioned blending ratio, the optimal condition of O₂/C was located at around 0.65 Nm³ kg^?1. The co‐gasification was also simulated using Aspen Plus. It revealed that the simulation could provide a useful insight into the practical operation of co‐gasification. Copyright © 2011 John Wiley & Sons, Ltd.     

Cost‐competitive methane steam reforming in a membrane reactor for H2 production: Technical and economic evaluation with a window of a H2 selectivity

Techno‐economic viability studies of employing a membrane reactor (MR) equipped with H₂ separation membranes for methane steam reforming (MSR) were carried out for H₂ production in Korea using HYSYS®, a well‐known chemical process simulator, including economic analysis based on itemized cost estimation and sensitivity analysis (SA). With the reaction kinetics for MSR reported by Xu and Froment, the effect of a wide range of H₂ selectivity (10‐10,000) on the performance in an MR was investigated in this study. Because of the equilibrium shift owing to the Le Chatelier's principle, great performance of enhancement of methane conversion ( ) and H₂ yield and reaction temperature reduction was observed in an MR compared with a packed‐bed reactor (PBR). A window of a H₂ selectivity from 100 to 300 is proposed as a new criterion for better MR performance of MSR depending on potential applications from in‐depth analysis of and H₂ yield enhancements, a H₂ purity, and temperature reduction. In addition, economic analysis to evaluate the feasibility of an MR technology for MSR was carried out focusing on a levelized cost of H₂ based on itemized cost estimation of capital and operating costs as well as SA. Techno‐economic assessment showed 36.7% cost reduction in an MR compared with a PBR and revealed that this MR technology can be possibly opted for a cost‐competitive H₂ production process for MSR.     

Thermo-economic comparative analysis of solar-assisted and carbon capture integrated conventional cogeneration plant of power and process steam

A thermo-economic comparative analysis of steam production using a solar-assisted cogeneration (SACG) and a conventional cogeneration plant (CCG) with and without carbon capture systems has been conducted. The plants considered to produce electricity and process steam of 500 ton/h. Several parametric studies were carried out on the effect of natural gas price, steam quality, gas turbine capacity and solar multiples (SMs) on the Levelized cost of steam (LCS). Results show that in a CCG plant that comprises a 20 MWe gas turbine, the LCS is $8.11/ton of steam and $3.61/ton of steam from a plant with 100 MWe gas turbine capacity for a natural gas price of $3/GJ. The cost analysis of SACG plant with SM of 0.1 shows that 28% of the total annualized costs are solar system related while it contributed only about 9.17% of the annual steam generation. An increase in SM from 0.1 to 0.9 increases the CO₂ avoidance from 61 to 262 ktons/annum for the SACG plant with 20 MWe gas turbine. CCG plants with CO₂ capture technologies were found to have lower LCS in comparison with that of SACG plant. The impact of carbon credit implementation on the LCS has been also investigated and reported in this article.     

An economic and environmental assessment of biomass utilization in lignite‐fired power plants of Greece

The environmental and socio‐economic impacts of biomass utilization by co‐firing with brown coal in an existing thermoelectric unit in Greece or through its pure combustion in a new plant were studied and evaluated in this work. The 125 MW_e lignite‐fired power plant in Ptolemais Power Station (Western Macedonia) was used as reference system. The environmental benefits of the alternative biomass exploitation options were quantified based on the life cycle assessment methodology, as established by SETAC, while the BIOSEM technique was used to carry out socio‐economic calculations. The obtained results showed clear environmental benefits of both biomass utilization alternatives in comparison with the reference system. In addition, co‐firing biomass with lignite in an existing unit outperforms the combustion of biomass exclusively in a new plant, since it exhibits a better environmental performance and it is a low risk investment with immediate benefits. A biomass combustion unit requires a considerably higher capital investment and its benefits are more evident in the long run. Copyright © 2005 John Wiley & Sons, Ltd.     

Thermodynamic evaluation of integrated gasification combined cycle: Comparison between high‐ash and low‐ash coals

In the present study, a coal‐integrated gasification combined cycle power plant is simulated. A high‐ash coal and low‐ash coal are considered to compare the performance of the plant. The combined cycle is in typical commercial size with 450 MW capacity. The feeds are Tabas and Illinois #6 coals which approximately contain more than 30% and 10% ash and have higher heating values of 22.7 MJ/kg and 26.8 MJ/kg, respectively. Energy and exergy analyses are done by aspen plus ^® and ees , respectively. Energy analysis shows that the overall efficiencies of power plants using high‐ash and low‐ash coals are 33% and 28%, respectively. The result shows that in high‐ash case, 52 kg/s coal, 10 kg/s water, and 1050 kg/s air and in low‐ash case, 48 kg/s coal and 820 kg/s air are required for providing mentioned power, approximately. Exergy analysis shows that maximum exergy destruction is in heat recovery steam generator unit. Investigating the emissions shows that high percent of ash in the coal composition has slight effects on the IGCC pollution. Finally, from thermodynamic viewpoint, it is concluded that the high‐ash coal, like the conventional one, can be used as thermally efficient and environmentally compatible feed of IGCCs. Copyright © 2016 John Wiley & Sons, Ltd.     

Assessment of flexible energy vectors poly-generation based on coal and biomass/solid wastes co-gasification with carbon capture

This paper evaluates biomass and solid wastes co-gasification with coal for energy vectors poly-generation with carbon capture. The evaluated co-gasification cases were evaluated in term of key plant performance indicators for generation of totally or partially decarbonized energy vectors (power, hydrogen, substitute natural gas, liquid fuels by Fischer–Tropsch synthesis). The work streamlines one significant advantage of gasification process, namely the capability to process lower grade fuels on condition of high energy efficiency. Introduction in the evaluated IGCC-based schemes of carbon capture step (based on pre-combustion capture) significantly reduces CO₂ emissions, the carbon capture rate being higher than 90% for decarbonized energy vectors (power and hydrogen) and in the range of 47–60% for partially decarbonized energy vectors (SNG, liquid fuels). Various plant concepts were assessed (e.g. 420–425 MW net power with 0–200 MW_th flexible hydrogen output, 800 MW_th SNG, 700 MW_th liquid fuel, all of them with CCS). The paper evaluates fuel blending for optimizing gasification performance. A detailed techno-economic evaluation for hydrogen and power co-generation with CCS was also presented.     

An investigation of thermal behaviour of biomass and coal during co‐combustion using thermogravimetric analysis (TGA)

The thermal behaviour and kinetic analysis of biomass (cypress wood chips and macadamia nut shells) and Australian bituminous coal during combustion were studies using the thermogravimetric technique with four different heating rates under an air atmosphere. Each type of biomass was blended with coal at mass ratios (biomass:coal) of 95:5, 90:10, 85:15 and 80:20 to investigate the effect of coal as a supplementary fuel on thermal behaviour during the combustion process. Combustion of the individual samples and the blends took place in three steps comprising dehydration, devolatilisation and char oxidation. During co‐combustion, the thermal decomposition behaviour of the blends followed that of the weighted average of the individual samples in the blends. In kinetic analysis, thermal decomposition of biomass and coal appeared to take place independently, and thus, the activation energy of the blends can be calculated from that of the two components. No evidence for any significant synergetic effects or thermal interaction was found between either type of biomass and the coal during co‐combustion based on the lack of deviation from expected behaviour of the blends. Copyright © 2013 John Wiley & Sons, Ltd.     

Design and thermodynamic analysis of supercritical CO2 reheating recompression Brayton cycle coupled with lead‐based reactor

A reheating process is generally incorporated in a supercritical CO₂ (S‐CO₂) Brayton cycle to enhance its efficiency. The heat transfer process from the reactor coolant to the working fluid of the power cycle is a key issue encountered when designing reheating power systems for the lead‐based reactor. The traditional reheating system, called RH‐1, utilizes an intermediate coolant circuit. In this paper, a novel reheating system, called RH‐2, is proposed. It eliminates the intermediate coolant circuit and combines the processes of the primary heating and reheating in a single heat exchanger. A thermodynamic analysis of three different systems for the lead‐based reactor integrated with the S‐CO₂ power cycle with or without reheating was conducted to evaluate the performance of the proposed system. The results confirmed that the performance of RH‐2 was the best of all the three systems. Under the same reactor conditions, the system efficiency of RH‐2 was greater than those of RH‐1 and the recompression (no reheating) system by 1.2% and 1.7%, respectively. RH‐2 could also maintain higher efficiency when the main operating parameters varied. The efficiency of RH‐2 was higher at different core outlet temperatures and split ratios. The maximum efficiency at optimal maximum pressure of RH‐2 was greater than those of the other two systems. RH‐2 was less sensitive to the variations in the isentropic efficiencies of the components than the other two systems, while the turbine isentropic efficiency demonstrated a significantly higher impact on the system efficiency than the two compressors (approximately 3.8 times).     

Thermodynamic analysis of high‐ash coal‐fired power plant with carbon dioxide capture

A thermodynamic analysis of a 500‐MWe subcritical power plant using high‐ash Indian coal (base plant) is carried out to determine the effects of carbon dioxide (CO₂) capture on plant energy and exergy efficiencies. An imported (South African) low‐ash coal is also considered to compare the performance of the integrated plant (base plant with CO₂ capture plant). Chemical absorption technique using monoethanolamine as an absorbent is adopted in the CO₂ capture plant. The flow sheet computer program “Aspen Plus” is used for the parametric study of the CO₂ capture plant to determine the minimum energy requirement for absorbent regeneration at optimum absorber–stripper configuration. Energy and exergy analysis for the integrated plant is carried out using the power plant simulation software “Cycle‐Tempo”. The study also involves determining the effects of various steam extraction techniques from the turbine cycle (intermediate‐pressure–low‐pressure crossover pipe) for monoethanolamine regeneration. It is found that the minimum reboiler heat duty is 373 MW_th (equivalent to 3.77 MJ of heat energy per kg of CO₂ captured), resulting in a drop of plant energy efficiency by approximately 8.3% to 11.2% points. The study reveals that the maximum energy and exergy losses occur in the reboiler and the combustor, respectively, accounting for 29% and 33% of the fuel energy and exergy. Among the various options for preprocessing steam that is extracted from turbine cycle for reboiler use, “addition of new auxiliary turbine” is found to be the best option. Copyright © 2011 John Wiley & Sons, Ltd.     

Thermal‐economic analysis of a transcritical Rankine power cycle with reheat enhancement for a low‐grade heat source

A thermal‐economic analysis of a transcritical Rankine power cycle with reheat enhancement using a low‐grade industrial waste heat is presented. Under the identical operating conditions, the reheat cycle is compared to the non‐reheat baseline cycle with respect to the specific net power output, the thermal efficiency, the heat exchanger area, and the total capital costs of the systems. Detailed parametric effects are investigated in order to maximize the cycle performance and minimize the system unit cost per net work output. The main results show that the value of the optimum reheat pressure maximizing the specific net work output is approximately equal to the one that causes the same expansion ratio across each stage turbine. Relative performance improvement by reheat process over the baseline is augmented with an increase of the high pressure but a decrease of the turbine inlet temperature. Enhancement for the specific net work output is more significant than that for the thermal efficiency under each condition, because total heat input is increased in the reheat cycle for the reheat process. The economic analysis reveals that the respective optimal high pressures minimizing the unit heat exchanger area and system cost are much lower than that maximizing the energy performance. The comparative analysis identifies the range of operating conditions when the proposed reheat cycle is more cost effective than the baseline. Copyright © 2012 John Wiley & Sons, Ltd.     

High-efficiency power production from natural gas with carbon capture

A unique electricity generation process uses natural gas and solid oxide fuel cells at high electrical efficiency (74%HHV) and zero atmospheric emissions. The process contains a steam reformer heat-integrated with the fuel cells to provide the heat necessary for reforming. The fuel cells are powered with H₂ and avoid carbon deposition issues. 100% CO₂ capture is achieved downstream of the fuel cells with very little energy penalty using a multi-stage flash cascade process, where high-purity water is produced as a side product. Alternative reforming techniques such as CO₂ reforming, autothermal reforming, and partial oxidation are considered. The capital and energy costs of the proposed process are considered to determine the levelized cost of electricity, which is low when compared to other similar carbon capture-enabled processes.     

Co-production system of hydrogen and electricity based on coal partial gasification with CO2 capture

To solve the problems of high cost and low efficiency of conventional co-production system of hydrogen and electricity with low hydrogen-to-electricity ratio, a novel co-production system based on coal partial gasification with CO₂ capture is proposed and thermodynamically analyzed. The new system integrates the conceptions of cascade conversion of coal and cascade utilization of syngas to realize the system with high efficiency, low cost, environmental friendliness and flexible hydrogen-to-electricity ratio. The performance of the new system is evaluated by an Aspen Plus model and effects of the operating conditions are also studied. It is found that the system with capturing CO₂ of 59.7% and hydrogen-to-electricity ratio of 4.76 holds a high exergy efficiency of 54.3% when the carbon conversion ratio of the pressurized fluidized bed (PFB) gasifier is equal to 0.7. The carbon conversion ratio of the PFB gasifier is a dominant factor to decide the performance of system. In comparison with the series-type co-production system, the parallel-type co-production system and separate production system, the new system proposed in this study has exergy-saving efficiency of 17.7%, 15.1% and 8.9%, respectively.     

Process optimization and robustness analysis of municipal solid waste gasification using air‐carbon dioxide mixtures as gasifying agent

In this work, a computational fluid dynamics (CFD) model was coupled with an advanced statistical strategy combining design of experiments (DoE) and the Monte Carlo method to comparatively optimize and test the robustness of two municipal solid waste (MSW) gasification processes one using air‐carbon dioxide (CO₂) mixtures as a gasifying agent and the other using air alone. A 3^k full factorial design of 18 computer simulations was performed using as input factors for air‐CO₂ mixtures the equivalence ratio and CO₂‐to‐MSW ratio, while MSW feeding rate and air flow rate were used for air gasification. The selected responses were CO₂, H₂, CO, and C_nH_m generation, CH₄/H₂ and H₂/CO ratios, carbon conversion, and cold gas efficiency (CGE). Findings were that DoE allowed determining the best‐operating conditions to achieve optimal syngas quality. Monte Carlo identified the best‐operating conditions reaching a more stable high‐quality syngas. Air‐CO₂ mixture gasification showed enhanced responses with major improvements in CO₂ conversion and CGE, both up to a 13% increase. The optimal operating conditions that set the optimized responses showed to not always imply the most stable set of values to operate the system. Finally, this combined optimization process performance revealed to grant professionals the ability to make smarter decisions in an industrial environment.