Meeting the Paris Agreement will most likely require the combination of CO2 capture and biomass in the industrial sector, resulting in net negative emissions. CO2 capture within the industry has been extensively investigated. However, biomass options have been poorly explored, with literature alluding to technical and economic barriers. In addition, a lack of consistency among studies makes comparing the performance of CO2 capture and/or biomass use between studies and sectors difficult. These inconsistencies include differences in methodology, system boundaries, level of integration, costs, greenhouse gas intensity of feedstock and energy carriers, and capital cost estimations. Therefore, an integrated evaluation of the techno-economic performance regarding CO2 capture and biomass use was performed for five energy-intensive industrial sub-sectors. Harmonization results indicate that CO2 mitigation potentials vary for each sub-sector, resulting in reductions of 1.4-2.7 t CO2/t steel (77%-149%), 0.7 t CO2/t cement (92%), 0.2 t CO2/t crude oil (68%), 1.9 t CO2/t pulp (1663%-2548%), and 34.9 t CO2/t H-2 (313%). Negative emissions can be reached in the steel, paper and H2 sectors. Novel bio-based production routes might enable net negative emissions in the cement and (petro) chemical sectors as well. All the above-mentioned potentials can be reached for 100 (sic)/t CO2 or less. Implementing mitigation options could reduce industrial CO2 emissions by 10 Gt CO2/y by 2050, easily meeting the targets of the 2 degrees C scenario by the International Energy Agency (1.8 Gt CO2/y reduction) for the industrial sector and even the Beyond 2 degrees C scenario (4.2 Gt CO2/y reduction).

This study analyses the impacts of technological improvements and increased operating experience on the techno-economic performance of integrated gasification (IG) facilities. The facilities investigated produce electricity (IGCC) or FT-liquids with electricity as by-product (IG-FT).Results suggest that a state-of-the-art (SOTA) coal-fired IGCC without CO2 capture has electricity production costs of 17 (sic)/GJ (60 (sic)/MWh) with the potential to decrease to 11 (sic)/GJ (40 (sic)/MWh) in the long term. Specific direct CO2 emissions may drop from about 0.71 kg CO2/kWh to 0.59 kg CO2/kWh. If CO2 is captured, production costs may increase to 23 (sic)/GJ (83 (sic)/MWh), with the potential to drop to 14 (sic)/GJ (51 (sic)/MWh) in the long term. As a result, CO2 avoidance costs would decrease from 35 (sic)/t CO2 to 18 (sic)/t CO2. The efficiency penalty due to CCS may decrease from 8.8%(pt) to 3.7%(pt).CO2 emissions can also be reduced by using torrefied biomass (TOPS) instead of coal. Production costs of a SOTA TOPS-fired IGCC without CO2 capture are 18-25 (sic)/GJ (64-92 (sic)/MWh). In the long term, this may drop to 12 (sic)/GJ (44 (sic)/MWh), resulting in CO2 avoidance costs of 7 (sic)/t CO2. The greatest reduction in anthropogenic CO2 emissions is obtained by using biomass combined with carbon capture and storage (CCS). A SOTA TOPS-fired IGCC with CCS has, depending on the biomass price, production costs of 25-35 (sic)/GJ (91-126 (sic)/MWh) with CO2 avoidance costs of 19-40 (sic)/t CO2. These values may decrease to 15 (sic)/GJ (55 (sic)/MWh) and 12 (sic)/t CO2 avoided in the long term. As carbon from biomass is captured, specific direct CO2 emissions are negative and estimated at -0.93 kg CO2/kWh for SOTA and -0.59 kg CO2/kWh in the long term. Even though more carbon is sequested in the future concepts, specific emissions drop due to an increase in the energetic conversion efficiency of the future facilities.New technologies in IC-FT facilities have a slightly smaller impact on production costs. In the long term, production costs of FT-liquids from coal may drop from 13 (sic)/GJ to 9 (sic)/GJ if CO2 is vented and from 15 (sic)/GJ to 10 (sic)/GJ if CCS is applied. The use of TOPS results in 15-23 (sic)/GJ (Vent) and 17-24 (sic)/GJ (CCS) for SOTA facilities. These production costs may drop to 11-18 (sic)/GJ (Vent) and 12-19 (sic)/GJ (CCS) in the long term. Contrary to the IGCC cases, the coal-fired IC-FT facility shows the lowest CO2 avoidance costs. The CO2 emission of coal to FT-liquids with CCS is, however, similar to gasoline/diesel production from crude oil. (C) 2013 Elsevier Ltd. All rights reserved.

This study analyses the impact of technological improvements and increased operating experience on the techno-economic performance of integrated gasification facilities producing electricity and/or transportation fuels. Also, the impact of using torrefied biomass instead of coal and/or applying CCS is examined. Results indicate that current production costs of electricity and/or transportation fuels are above market prices. Future improvements, however, could reduce production costs sufficiently to make gasification facilities economical. Furthermore, although CCS can be used to reduce CO2 emissions at relative low CO2 avoidance costs, only the use of biomass allows the production of carbon neutral electricity and/or transportation fuels and in combination with CCS can even result in negative CO2 emissions.

This study aims to investigate the technological and economic prospects of integrated gasification facilities for power (IGCC) and Fischer-Tropsch (FT) liquid production with and without CCS over time. For this purpose, a component based experience curve was constructed and applied to identify the potential performance improvement of integrated gasification facilities. The results of the experience curve were compared with a bottom-up technology analysis conducted in previous work (Meerman etal., 2012).Results indicate that substantial cost reductions and performance improvements are possible, especially for IGCC with CCS. For instance, the costs of electricity production (COE) may decrease from 82 (sic)(2008)/MWh at present to 50 (sic)(2008)/MWh in 2050, if solid oxide fuel cells become commercially available (with a constant coal price of 2.25 (sic)(2008)/GJ). This cost decrease can only be realized if installed IGCC capacity increase to over 600 GW(e) and installed CCS capacity to over 3000 GW(e), equivalent. Also IGCC without CCS have considerable learning potential, with COE projected to decrease from the current 60 to 40 (sic)(2008)/MWh in the long term. Furthermore, the COE of IGCC without CCS could be competitive with the current market price in the short term. Initial support is, however, needed to realize the first 20 GW(e).Currently, coal-based FT-liquids are already competitive at an oil price of 77 (sic)(2008)/bbl for FT-liquids without CCS and of 83 (sic)(2008)/bbl with CCS, resulting in CO2 capture costs of only 11 (sic)(2008)/t CO2. By 2050, production costs of FT-liquids could drop to 9.3 (sic)(2008)/GJ for FT-liquids without CCS and to 10 (sic)(2008)/GJ for FT-liquids with CCS. To realize this cost reduction, an installed capacity of about 430 GW(th_FT) is needed.The bottom-up and the component based experience curve analyses gave comparable trends regarding the potential development of efficiency, capital costs and production costs for a scenario with a strong growth in IGCC, FT and CCS capacity. The main advantage of combining the two approaches is that it becomes clear how cost reductions can be achieved, what kind of capacity development and the time frame is required to reach the projected improvements. (C) 2013 Elsevier Ltd. All rights reserved.

This study aimed to identify the optimal techno-economic configuration of CO2 capture at steam methane reforming facilities using currently available technologies by means of process simulations. Results indicate that the optimal system is CO2 capture with ADIP-X located between the water-gas shift and pressure swing adsorption units. Process simulations of this system configuration showed a CO2 emission reduction of 60% at 41 (sic)/t CO2 avoidance. This is at the lower end of the range reported in open literature for CO2 capture at refineries (26-82 (sic)/t CO2) and below the avoidance costs for CO2 capture at natural gas-fired power plants (44-93 (sic)/t CO2). CO2 avoidance costs are dominated by the natural gas consumption, responsible for up to 66% of total costs. Using imported steam and electricity can reduce CO2 avoidance costs by 45%. Addition of small amounts of piperazine to aqueous MDEA solutions results in up to 70% smaller absorbers or 10% lower reboiler heat duty. Optimising the whole capture process instead of individual units resulted in lower piperazine concentrations than the common industrial practice (3 mass% vs. 5 mass%). Finally, keeping the solvent rate constant when operating the capture unit below its design load resulted in a lower specific energy for CO2 capture than when the solvent rate was downscaled with the syngas flow. (C) 2012 Elsevier Ltd. All rights reserved.

This paper investigates the economics of integrated gasification polygeneration (IG-PG) facilities and assesses under which market conditions flexible facilities outperform static facilities. In this study, the facilities use Eucalyptus wood pellets (EP), torrefied wood pellets (TOPS) and Illinois #6 coal as feedstock to produce electricity, FT-liquids, methanol and urea. All facilities incorporate CCS. The findings show production costs from static IG-PG facilities ranging between 12 and 21 €/GJ using coal, 19–33 €/GJ using TOPS and 22–38 €/GJ using EP, which is above the average market prices. IG-PG facilities can become competitive if capital costs drop by 10%–27% for coal based facilities. Biomass based facilities will need lower biomass pellet prices or higher CO2 credit prices. Biomass becomes competitive with coal at a CO2 credit price of 50–55 €/t CO2. Variations in feedstock, CO2 credit and electricity prices can be offset by operating a feedstock flexible IG-PG facility, which can switch between coal and TOPS, thereby altering its electricity production. The additional investment is around 0.5% of the capital costs of a dedicated coal based IG-PG facility. At 30 €/t CO2, TOPS will be the preferred feedstock for 95% of the time at a feedstock price of 5.7 €/GJ. At these conditions, FT-liquids (gasoline/diesel) can be produced for 15.8 €/GJ (116 $/bbl). Historic records show price variations between 5.7 and 7.3 €/GJ for biomass pellet, 1.0–5.6 €/GJ for coal and 0–32 €/t CO2. Within these price ranges, coal is generally the preferred feedstock, but occasionally biomass is preferred. Lower biomass prices will increase the frequency of switching feedstock preference from coal to biomass, raising the desire for flexibility. Of the three investigated chemicals, an IG-PG facility producing FT-liquids benefits the most from flexibility. Our study suggests that if the uncertainty in commodity prices is high, a small additional investment can make flexible IG-PG facilities attractive.

This article investigates technical possibilities and performances of flexible integrated gasification polygeneration (IG-PG) facilities equipped with CO2 capture for the near future. These facilities can produce electricity during peak hours, while switching to the production of chemicals during off-peak hours.Several simulations were performed to investigate the influence of substituting feedstock and production on IG-PG facility output, load and efficiency. These simulations were done using a detailed AspenPlus simulation model of a Shell entrained flow gasifier combined with conversion facilities. In this model carbon-rich feedstocks (oil residues, coal and biomass) were converted to a variety of products (H-2, electricity, FT-liquids, methanol and urea) using state-of-the-art technology. The size of the gasifier was limited to the equivalent of 2000 MWth II #6 coal input.Overall efficiency of the simulated non-flexible configurations to convert pure coal or pure wood pellets to electricity (40%(HHV) vs 38%(HHV)). FT-liquids (60%(HHV) vs 55%(HHV)), methanol (53%(HHV) vs 49%(HHV)) or urea (51%(HHV) vs 47%(HHV)) are in good agreement with the literature. Using torrefied wood pellets instead of pure wood pellets reduces the penalty drop in efficiency compared to coal. Moreover, torrefied wood pellets have superior energetic density, handling and feeding compared to wood pellets.In this analysis, the H-2:CO ratio of the sweet syngas was fixed to match FT-liquids criterion. As a result, overall CO2 capture rates are low, around 56-65%, depending on the feedstock used. Still, especially with FT-liquids and methanol production, CO2 emissions at the facility are significantly reduced; less than 20% of the carbon feedstock entering the facility is emitted with the flue gas. Applying biomass and CO2 capture shows great opportunities to produce CO2-neutral electricity or chemicals. When the biomass fraction exceeds 40% on an energy basis, production is CO2-neutral, independent of what is produced.Biomass can be co-fed up till 50% on an energy basis. Higher fractions cause significant fouling on cooling equipment. A small part-load penalty is observed during the substitution of coal by biomass. When changing from pure coal to pure wood pellets, the power case suffers a 2.5% efficiency drop, while all three chemical cases have an efficiency drop of less than 1%. At the same time total output is reduced to 67-69%, mainly because of the lower energy density of biomass. By over-dimensioning the gasifier and gas cleanup and optimisation section this drop can be eliminated.The syngas can be tailored to the desired composition regardless of the used feedstock Therefore, the chemical conversion sections only have to cope with a reduction in syngas flow and not with a change in syngas composition. Altering production between chemicals and electricity is possible, although the load of the conversion sections should remain between 40% and 100% to prevent operational problems. This gives a high degree of flexibility.Complete substitution between chemical and power production while using the same feedstock is possible for the methanol and urea cases. The FT-liquids case is restricted to 60-100% load of the chemical conversion section to prevent that the gas turbine load is reduced below 40%. The economic aspects of flexible IG-PG facilities are addressed in part B. (C) 2011 Elsevier Ltd. All rights reserved.

This paper evaluated the economic effects of introducing flexibility to state-of-the-art integrated gasification co-generation (IG-CG) facilities equipped with CO2 capture. In a previous paper the technical and energetic performances of these flexible IG-CG facilities were evaluated. This paper investigated how market conditions affect the economics of flexible IG-CG facilities by analyzing several case studies. The IG-CG facilities used Eucalyptus wood pellets, torrefied wood pellets and Illinois #6 coal as feedstock and produced electricity, FT-liquids, methanol and urea. Results indicated that currently biomass is, compared to coal, too expansive. Therefore, feedstock flexibility is not attractive. Production flexibility between chemical and electricity production under current economic conditions reduces the profitability of the IG-CG facility. Therefore, with state-of-the-art technology and the current economic climate, introducing flexibility to IG-CG facilities is not economically profitable.

The aim of this study was to identify and analyse the technical and energy impacts of feedstock and product flexibility on integrated gasification co-generation facilities (IGCF) using current commercial ready technologies. The evaluation was twofold: 1) to identifying bottlenecks and possible de-bottleneck solutions and 2) to analyse flexibility effects on overall plant performance. Results indicate that flexibility is technically possible. Overall plant performance shows a minor drop in efficiency when switching from coal to Eucalyptus. When using torrefied biomass this drop almost completely disappears.