• Energy Research

This study developed a method to assess the techno-economic performance and spatial footprint of CO2 capture infrastructure configurations in industrial zones. The method has been successfully applied to a cluster of sixteen industrial plants in the Dutch industrial Botlek area (7.1 MtCO2/y) for 2020–2030. The configurations differ inter alia regarding capture technology (post-, pre-, oxyfuel combustion) and location of capture components (centralized vs. plant site). Results indicate that oxyfuel combustion with centralized oxygen production and decentralized CO2 compression is the most cost effective and realistic configuration when applying CO2 capture to all industrial plants (61€/tCO2; 5.8 MtCO2/y avoided), mainly due to relatively low energy costs compared to post- and pre-combustion. However, oxyfuel combustion at plant level is economically preferable when capturing CO2 from only the three largest industrial plants. For post-combustion, a separated absorber-stripper configuration (73€/tCO2; 7.1 MtCO2/y avoided) is preferable from a cost perspective, due to economic scale effects of capture equipment. The optimal pre-combustion configuration shows a slightly less favorable performance (81€/tCO2; 4.4 MtCO2/y avoided). Whereas many industrial plants have insufficient space available for capture equipment, centralized/hybrid configurations show no insurmountable space issues. The deployment of the most favorable configurations is addressed in Part B.

Abstract This study assesses whether the deployment of CO 2 capture technologies in the European industrial sector would result in significant changes in the emissions of air pollutants (NO x , SO 2 , PM, and NH 3 ) in the short term. The industrial sectors investigated were: cement, petroleum refineries, and iron and steel. The analysis included onsite emissions and changes associated with grid electricity consumption due to CO 2 capture. Post-combustion capture using monoethanolamine (MEA) was considered for the cement sector and petroleum refineries, and Top Gas Recycling Blast Furnace (TGRBF) with vacuum-pressure swing adsorption (VPSA) for the iron and steel sector. The results show that when all three industrial sectors in the EU-27 are fully equipped with CO 2 capture, industrial SO 2 emissions in the EU-27 may decrease by 40–70% whereas NH 3 emissions may increase by 120–520% (equivalent to 2–8% of total European emissions). The large increase in NH 3 emissions is due to the degradation of MEA. Cement and petroleum refineries account for nearly all these changes. The results also show limited impact (within ±10% of EU-27 industrial emissions) on NO x and PM emissions. Emission changes due to electricity import/export are found to be equally important as onsite emission changes. For the iron and steel sector, the changes in National Emissions Ceilings Directive (NECD) emissions are found to be limited for the selected CO 2 capture technique under conservative assumptions. However, the changes in the NECD emissions could vary largely depending on how the steel mill will adapt and operate their coke oven batteries that supply the coke to the blast furnace (BF).

Abstract CO2 emissions from distributed energy systems are expected to become increasingly significant, accounting for about 20% for current global energy-related CO2 emissions in 2030. This article reviews, assesses and compares the techno-economic performance of CO2 capture from distributed energy systems taking into account differences in timeframe, fuel type and energy plant type. The analysis includes the energy plant, CO2 capture and compression, and distributed transport between the capture site and a trunk pipeline. Key parameters, e.g., capacity factor, energy prices and interest rate, were normalized for the performance comparison. The findings of this study indicate that in the short-mid term (around 2020–2025), the energy penalty for CO2 capture ranges between 23% and 30% for coal-fired plants and 10–28% for natural gas-fired plants. Costs are between 30 and 140 €/tCO2 avoided for plant scales larger than 100 MWLHV (fuel input) and 50–150 €/tCO2 avoided for 10–100 MWLHV. In the long-term (2030 and beyond), the energy penalty for CO2 capture might reduce to between 4% and 9% and the costs to around 10–90 €/tCO2 avoided for plant scales larger than 100 MWLHV, 25–100 €/tCO2 avoided for 10–100 MWLHV and 35–150 €/tCO2 avoided for 10 MWLHV or smaller. CO2 compression and distributed transport costs are significant. For a distance of 30 km, 10 €/tCO2 transported was calculated for scales below 500 tCO2/day and more than 50 €/tCO2 transported for scales below 5 tCO2/day (equivalent to 1 MWLHV natural gas). CO2 compression is responsible for the largest share of these costs. CO2 capture from distributed energy systems is not prohibitively expensive and has a significant cost reduction potential in the long term. Distributed CO2 emission sources should also be considered for CCS, adding to the economies of scale of CO2 transport and storage, and optimizing the deployment of CCS.

AbstractTechno-economic performance of post-combustion CO2 capture from industrial Natural Gas Combined Cycle (NGCC) Combined Heat and Power plants (CHPs) of scales from 50 MWe to 200 MWe were compared with large-scale (400 MWe) NGCC for short-term (2010) future. Four components were included in the system boundaries: NGCC, CO2 capture, compression, and branch CO2 pipeline. Effects of plant scale, operational conditions, part-load efficiency and costs of system components were investigated.The results show that CO2 capture energy requirement for industrial NGCC-CHPs may be up to 16%. lower than for 400 MWe NGCCs. Load increase to meet CO2 capture energy requirement also increases the plant efficiency and consequently offsets part of CO2 capture energy requirement. CO2 avoidance cost of below 45 €/t CO2 may be feasible.

New synthesis shows what a wasted decade means for the climate pact made in Paris. New synthesis shows what a wasted decade means for the climate pact made in Paris.

Abstract An up-to-date techno-economic assessment was conducted on CO2 emissions reduction potential in the Japanese iron and steel industry for 2030. The following mitigation measures were investigated: (i) maximized installation of best available technologies (BAT scenario), (ii) increased use of coke substitutes in blast furnaces, and (iii) increased use of obsolete steel scrap. For measure (iii), this study assessed the obsolete scrap use in the integrated steelmaking (BF-BOF) route, rather than increasing steel production from the electric arc furnace (EAF) route. CO2 capture and storage (CCS) was not considered due to large deployment uncertainty. The results showed that 20 Mt–CO2 of emissions reductions, equivalent to 12% of the industry's total emissions in 2010, can be achieved in 2030 compared with a frozen technology scenario. More than 9 Mt–CO2 reduction was attributable to the enhanced use of obsolete scrap in the BF-BOF route. Consequently, the industry's emissions reduce by about 7 Mt–CO2 or 4% below 2010 levels. Almost all domestically recovered obsolete scrap can be fully consumed solely by increasing the scrap use in basic oxygen furnaces (BOF). Moreover, the increase in average copper concentration in the BF-BOF steel due to the increased obsolete scrap use was found unlikely to limit the production of high-quality steel products. In comparison with a scenario that only considered measure (i) and assuming a 15% real interest rate, CO2 mitigation cost curves for 2030 showed that the CO2 mitigation costs were below US$2010 20/t-CO2 for measure (ii) and around US$2010 110/t-CO2 for measure (iii). Compared to the marginal abatement costs calculated for 2030 to reduce Japan's GHG emissions by 20%–25% from 1990 levels (about US$2010 67–640/t-CO2) reported in the literature, all three measures may become economically viable. The increased use of obsolete scrap in the BF-BOF route can become an interesting option for Japanese steelmakers to stimulate the steel scrap market and achieve economical global CO2 emissions reductions while maintaining international competitiveness in the midterm future.

Abstract This study compares greenhouse gas (GHG) emissions projections in 2030 under current policies and those under 2030 mitigation targets for nine key non-G20 countries, that collectively account for about 5 % of global total emissions today. These include the four largest non-G20 fossil CO2 emitting Parties to the UN climate convention pre- Paris Agreement (Iran, Kazakhstan, Thailand and Ukraine) and one of the largest land-use GHG emitters in the world (Democratic Republic of the Congo). Other countries assessed include major economies in their respective regions (Chile, Colombia, Morocco and the Philippines). In addition to economy-wide GHG emissions projections, we also assessed the projected GHG emissions peak year and the progression of per capita GHG emissions up to 2030. Our GHG emissions projections are also compared with previous studies. On economy-wide GHG emissions, Colombia, Iran, Morocco, and Ukraine were projected to likely meet or significantly overachieve their unconditional 2030 targets with existing policies, while DRC and Thailand would come very close to their targets. Kazakhstan and the Philippines would need to strengthen their action to meet their targets, while Chile recently raised its 2030 target ambition. Only Colombia and Ukraine are projected to have peaked their emissions by 2030. Per capita GHG emissions excluding land-use under current policies were projected to increase in all countries from 2010 levels by 8 % to over 40 % depending on the country. While the impact of the COVID-19 crisis on 2030 emissions is highly uncertain, our assessment on the target achievement would not change for most countries when the emission reductions estimated for 2020 in the literature were assumed to remain in 2030. The findings of this study highlight the importance of enhanced and frequent progress-tracking of climate action of major emitters outside G20, as is currently done for G20 members, to ensure that the global collective progress will become aligned with the pathways toward Paris climate goals.

Electric vehicles (EVs) are currently seen as an option for a more sustainable transportation sector, but it is not yet clear how to supply them with electricity whilst striving for low costs and low CO2 emissions. Renewable sources can supply electricity with low emissions, but their penetration rate is still insufficient to meet current demand, let alone the extra demand of EVs. A promising option is supply by Combined Heat and Power (CHP) plants with high combined efficiencies, but an in-depth evaluation of the benefits of combining of EVs and CHP plants is still missing. Therefore, this study evaluates the performance of four different types of CHP plants to power electric vehicles, as compared to use of electricity from the grid. The performance of CHP plants is simulated using detailed datasets of the composition of a future power system, the demand for household electricity and heat, and technical specifications of CHP plants and electric vehicles. We find that the lowest abatement costs of 60–190 €/tCO2 are achieved with grid electricity based on a low-carbon electricity mix compared to a business-as-usual electricity mix with marginal emissions of 450–500 gCO2/kW h. When electricity is supplied by CHP plants, emissions are 1000 to 400 gCO2/kW h, and abatement costs are 165–940 €/tCO2. We did not observe added benefits of joint implementation of CHP plants and EVs: the timing of CHP electricity supply and EV electricity demand did not match well, and abatement costs were not lowered