Techno-economic and environmental evaluations of large scale gasification-based CCS project in Romania

Gasification is a promising technology in terms of reducing carbon capture energy and cost penalties as well as for multi-fuel multi-product operation capability. The paper evaluates two carbon capture options in terms of main techno-economic indicators. The first option involves pre-combustion capture, the syngas being catalytically shifted to convert carbon species into CO₂ and H₂. Gas–liquid absorption is used for separate H₂S and CO₂ capture, then clean gas is used for power generation. The second capture option is based on post-combustion capture using chemical absorption. The most promising gasifiers were evaluated in a CCS design.     

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.     

Evaluation of power generation schemes based on hydrogen-fuelled combined cycle with carbon capture and storage (CCS)

IGCC is a power generation technology in which the solid feedstock is partially oxidized to produce syngas. In a modified IGCC design for carbon capture, there are several technological options which are evaluated in this paper. The first two options involve pre-combustion arrangements in which syngas is processed, either by shift conversion or chemical looping, to maximise the hydrogen level and to concentrate the carbon species as CO₂. After CO₂ capture by gas-liquid absorption or chemical looping, the hydrogen-rich gas is used for power generation. The third capture option is based on post-combustion arrangement using chemical absorption.Investigated coal-based IGCC case studies produce 400-500 MW net power with more than 90% carbon capture rate. Principal focus of the paper is concentrated on evaluation of key performance indicators for investigated carbon capture options, the influence of various gasifiers on carbon capture process, optimisation of energy efficiency by heat and power integration, quality specification of captured CO₂. The capture option with minimal energy penalty is based on chemical looping, followed by pre-combustion and post-combustion.     

Assessment of calcium-based chemical looping options for gasification power plants

This paper evaluates various calcium-based chemical looping concepts to be applied in Integrated Gasification Combined Cycle (IGCC) plants for decarbonised energy vectors poly-generation (with emphasis on power generation and hydrogen and power co-generation). Two calcium-based chemical looping configurations were analysed. The first concept is based on post-combustion capture using the flue gases resulted from the power block (combined cycle gas turbine). The second concept is based on pre-combustion capture, the calcium-based chemical looping systems being used simultaneous to capture carbon dioxide (by sorbent enhanced water gas shift) and to concentrate the syngas energy in the form of hydrogen-rich gas.     

Techno-economic and environmental performances of glycerol reforming for hydrogen and power production with low carbon dioxide emissions

This paper is evaluating from the conceptual design, thermal integration, techno-economic and environmental performances points of view the hydrogen and power generation using glycerol (as a biodiesel by-product) reforming processes at industrial scale with and without carbon capture. The evaluated hydrogen plant concepts produced 100,000 Nm³/h hydrogen (equivalent to 300 MW_th) with negligible net power output for export. The power plant concepts generated about 500 MW net power output. Hydrogen and power co-generation was also assessed. The CO₂ capture concepts used alkanolamine-based gas–liquid absorption. The CO₂ capture rate of the carbon capture unit is at least 90%, the carbon capture rate of the overall reforming process being at least 70%. Similar designs without carbon capture have been developed to quantify the energy and cost penalties for carbon capture. The various glycerol reforming cases were modelled and simulated to produce the mass & energy balances for quantification of key plant performance indicators (e.g. fuel consumption, energy efficiency, ancillary energy consumption, specific CO₂ emissions, capital and operational costs, production costs, cash flow analysis etc.). The evaluations show that glycerol reforming is promising concept for high energy efficiency processes with low CO₂ emissions.     

Pre-combustion, post-combustion and oxy-combustion in thermal power plant for CO2 capture

This paper presents a summary of technical-economic studies. It allows evaluating, in the French context, the production cost of electricity derived from coal and gas power plants with the capture of CO₂, and the cost per tonne of CO₂ avoided. Three systems were studied: an Integrated Gasification Combined Cycle (IGCC), a conventional combustion of Pulverized Coal (PC) and a Natural Gas Combined Cycle (NGCC). Three main methods were envisaged for the capture of CO₂: pre-combustion, post-combustion and oxy-combustion.For the IGCC, two gasification types have been studied: a current technology based on gasification of dry coal at 27 bars (Shell or GE/Texaco radiant type) integrated into a classical combined cycle providing 320 MWe, and a future technology (planned for about 2015–2020) based on gasification of a coal–water mixture (slurry) that can be compressed to 64 bars (GE/Texaco slurry type) integrated into an advanced combined cycle (type H with steam cooling of the combustion turbine blades) producing a gross power output of 1200 MWe.     

Evaluation of syngas-based chemical looping applications for hydrogen and power co-generation with CCS

This paper evaluates hydrogen and power co-generation based on coal-gasification fitted with an iron-based chemical looping system for carbon capture and storage (CCS). The paper assess in details the whole hydrogen and power co-production chain based on coal gasification. Investigated plant concepts of syngas-based chemical looping generate about 350–450 MW net electricity with a flexible output of 0–200 MW_th hydrogen (based on lower heating value) with an almost total decarbonisation rate of the coal used.     

Performance and costs of power plants with capture and storage of CO2

This paper assesses the three leading technologies for capture of CO₂ in power generation plants, i.e., post-combustion capture, pre-combustion capture and oxy-fuel combustion. Performance, cost and emissions data for coal and natural gas-fired power plants are presented, based on information from studies carried out recently for the IEA Greenhouse Gas R&D Programme by major engineering contractors and process licensors. Sensitivities to various potentially significant parameters are assessed.     

In-situ mineralization of carbon dioxide in a coal-fired power plant

Mitigation of anthropogenic carbon dioxide is needed in order to allow societies to maintain the existing carbon-based infrastructure, while minimizing the effects of carbon dioxide (CO₂) on the earth eco-system. A system that consists of pressure swing adsorption and in-situ mineralization unit was introduced to capture carbon dioxide (CO₂) from a 700 MW pulverized coal-fired power plant. Results from the work demonstrate that pressure swing adsorption for post-combustion carbon capture consumed the least energy, followed by biomass co-firing, pre-combustion cryogenic-membrane hybrid, and post-combustion monoethanolamine absorption. For carbon capture and sequestration, the pressure swing adsorption-fixation system was found to yield the lowest environmental burden factor, followed by off-site sequestration in deep sea and depleted underground oil/gas fields.     

Benchmarking of the pre/post-combustion chemical absorption for the CO2 capture

The aim of the article was to compare the pre- and post-combustion CO₂ capture process employing the chemical absorption technology. The integration of the chemical absorption process before or after the coal combustion has an impact on the power plant efficiency because, in both cases, the thermal energy consumption for solvent regeneration is provided by the steam extracted from the low pressure steam turbine. The solvent used in this study for the CO₂ capture was monoethanolamine (MEA) with a weight concentration of 30%. In the case of the pre-combustion integration, the coal gasification was analysed for different ratios air/fuel (A/F) in order to determine its influences on the syngas composition and consequently on the low heating value (LHV). The LHV maximum value (28 MJ/kg) was obtained for an A/F ratio of 0.5 kg_air/kg_fuel, for which the carbon dioxide concentration in the syngas was the highest (17.26%). But, considering the carbon dioxide capture, the useful energy (the difference between the thermal energy available with the syngas fuel and the thermal energy required for solvent regeneration) was minimal. The maximum value (61.59 MJ) for the useful energy was obtained for an A/F ratio of 4 kg_air/kg_fuel. Also, in both cases, the chemical absorption pre- and post-combustion process, the power plant efficiency decreases with the growth of the L/G ratio. In the case of the pre-combustion process, considering the CO₂ capture efficiency of 90%, the L/G ratio obtained was of 2.55 mol_solvent/mol_syngas and the heat required for the solvent regeneration was of 2.18 GJ/tCO₂. In the case of the post-combustion CO₂ capture, for the same value of the CO₂ capture efficiency, the L/G ratio obtained was of 1.13 mol_solvent/mol_{flue gas} and the heat required was of 2.80 GJ/tCO₂. However, the integration of the CO₂ capture process in the power plant leads to reducing the global efficiency to 30% in the pre-combustion case and to 38% to the post-combustion case.     

A comparison of electricity and hydrogen production systems with CO2 capture and storage. Part A: Review and selection of promising conversion and capture technologies

We performed a consistent comparison of state-of-the-art and advanced electricity and hydrogen production technologies with CO₂ capture using coal and natural gas, inspired by the large number of studies, of which the results can in fact not be compared due to specific assumptions made. After literature review, a standardisation and selection exercise has been performed to get figures on conversion efficiency, energy production costs and CO₂ avoidance costs of different technologies, the main parameters for comparison. On the short term, electricity can be produced with 85–90% CO₂ capture by means of NGCC and PC with chemical absorption and IGCC with physical absorption at 4.7–6.9 €ct/kWh, assuming a coal and natural gas price of 1.7 and 4.7 €/GJ. CO₂ avoidance costs are between 15 and 50 €/t CO₂ for IGCC and NGCC, respectively. On the longer term, both improvements in existing conversion and capture technologies are foreseen as well as new power cycles integrating advanced turbines, fuel cells and novel (high-temperature) separation technologies. Electricity production costs might be reduced to 4.5–5.3 €ct/kWh with advanced technologies. However, no clear ranking can be made due to large uncertainties pertaining to investment and O&M costs. Hydrogen production is more attractive for low-cost CO₂ capture than electricity production. Costs of large-scale hydrogen production by means of steam methane reforming and coal gasification with CO₂ capture from the shifted syngas are estimated at 9.5 and 7 €/GJ, respectively. Advanced autothermal reforming and coal gasification deploying ion transport membranes might further reduce production costs to 8.1 and 6.4 €/GJ. Membrane reformers enable small-scale hydrogen production at nearly 17 €/GJ with relatively low-cost CO₂ capture.     

Investigation of hydrogen and power co-generation based on direct coal chemical looping systems

This paper evaluates hydrogen and power co-generation based on direct coal chemical looping systems with total decarbonization of the fossil fuel. As an illustrative example, an iron-based chemical looping system was assessed in various plant configurations. The designs generate 300–450 MW net electricity with flexible hydrogen output in the range of 0–200 MW_th (LHV). The capacity of evaluated plant concepts to have a flexible hydrogen output is an important aspect for integration in modern energy conversion systems. The carbon capture rate of evaluated concepts is almost total (>99%). The paper presents in details evaluated plant configurations, operational aspects as well as mass and energy integration issues. For comparison reason, a syngas-based chemical looping concept and Selexol^®-based pre-combustion capture configuration were also presented. Direct coal chemical looping configuration has significant advantages compared with syngas-based looping systems as well as solvent-based carbon capture configurations, the more important being higher energy efficiency, lower (or even zero) oxygen consumption and lower plant complexity. The results showed a clear increase of overall energy efficiency in comparison to the benchmark cases.     

Hydrogen production and carbon dioxide enrichment using a catalytic membrane reactor with Ni metal catalyst and Pd-based membrane

We prepared a catalytic membrane reactor (CMR) by adopting a high-performance metal catalyst and Pd–Au membrane to investigate the possibility of hydrogen production concurrently with carbon dioxide enrichment (up to >80%) in a single-stage reactor from a simulated syngas of a coal gasification, via simultaneous WGS reaction and hydrogen separation process. The CO conversion was above 99% and the H₂ recovery was above 94% at del-P = 30 bar in a CMR. The best result for the concentration of the enriched CO₂ in the retentate side was 85.3% under the conditions of 350 °C, del-P = 30 bar and steam to carbon ratio of 2.0. These results show promise for a feasible simplified process able to achieve CO removal from a high-concentration CO mixture gas coming out of coal gasification via a water-gas shift reaction (WGS), to separate hydrogen and also to enrich CO₂ for pre-combustion capture and storage of CO₂ (CCS) in substitution for the conventional WGS and CO₂ separation stages in integrated gasification and combined cycle process integrated with CCS.     

Lime enhanced biomass gasification. Energy penalty reduction by solids preheating in the calciner

Hydrogen is expected to be one of the most important energy carriers in the future. Gasification process may be used to produce hydrogen when joined with carbon capture technologies. Furthermore, the combination of biomass gasification and carbon capture presents a significant technical potential in net negative greenhouse gas emissions. Lime enhanced biomass gasification process makes use of CaO as a high temperature CO₂ carrier between the steam biomass gasifier and an oxy-fired regenerator. Important energy penalties derive from the temperature difference between the reactors (around 250–300 °C). A cyclonic preheater similar to those used in the cement industry may improve the energetic efficiency of the process if the particles entering the regenerator reactor are heated up by the gas leaving this reactor. A lime enhanced biomass gasification system was modelled and simulated. A cyclonic preheater was included to evaluate the improvement. Results show an increase of the gasification chemical efficiency and a reduction of the energy consumption in the regenerator.     

Technoeconomic analysis of a methanol plant based on gasification of biomass and electrolysis of water

Methanol production process configurations based on renewable energy sources have been designed. The processes were analyzed in the thermodynamic process simulation tool DNA. The syngas used for the catalytic methanol production was produced by gasification of biomass, electrolysis of water, CO₂ from post-combustion capture and autothermal reforming of natural gas or biogas. Underground gas storage of hydrogen and oxygen was used in connection with the electrolysis to enable the electrolyser to follow the variations in the power produced by renewables. Six plant configurations, each with a different syngas production method, were compared. The plants achieve methanol exergy efficiencies of 59–72%, the best from a configuration incorporating autothermal reforming of biogas and electrolysis of water for syngas production. The different processes in the plants are highly heat integrated, and the low-temperature waste heat is used for district heat production. This results in high total energy efficiencies (∼90%) for the plants. The specific methanol costs for the six plants are in the range 11.8–25.3 €/GJ_exergy. The lowest cost is obtained by a plant using electrolysis of water, gasification of biomass and autothermal reforming of natural gas for syngas production.     

The cost of integration of zero emission power plants—A case study for the island of Cyprus

In this work, a technical, economic and environmental analysis is carried out for the estimation of the optimal option scenario for the Cyprus's future power generation system. A range of power generation technologies integrated with carbon capture and storage (CCS) were examined as candidate options and compared with the business as usual scenario. Based on the input data and the assumptions made, the simulations indicated that the integrated gasification combined cycle (IGCC) technology with pre-combustion CCS integration is the least cost option for the future expansion of the power generation system. In particular, the results showed that for a natural gas price of 7.9US$/GJ the IGCC technology with pre-combustion CCS integration is the most economical choice, closely followed by the pulverized coal technology with post-combustion CCS integration. The combined cycle technology can, also, be considered as alternative competitive technology. The combined cycle technologies with pre- or post-combustion CCS integration yield more expensive electricity unit cost. In addition, a sensitivity analysis has been also carried out in order to examine the effect of the natural gas price on the optimum planning. For natural gas prices greater than 6.4US$/GJ the least cost option is the use of IGCC technology with CCS integration. It can be concluded that the Cyprus's power generation system can be shifted slowly towards the utilization of CCS technologies in favor of the existing steam power plants in order not only to lower the environmental emissions and fulfilling the recent European Union Energy Package requirements but also to reduce the associated electricity unit cost.     

The outlook for improved carbon capture technology

Carbon capture and storage (CCS) is widely seen as a critical technology for reducing atmospheric emissions of carbon dioxide (CO₂) from power plants and other large industrial facilities, which are major sources of greenhouse gas emissions linked to global climate change. However, the high cost and energy requirements of current CO₂ capture processes are major barriers to their use. This paper assesses the outlook for improved, lower-cost technologies for each of the three major approaches to CO₂ capture, namely, post-combustion, pre-combustion and oxy-combustion capture. The advantages and limitations of each of method are discussed, along with the current status of projects and processes at various stages in the development cycle. We then review a variety of “roadmaps” developed by governmental and private-sector organizations to project the commercial roll-out and deployment of advanced capture technologies. For perspective, we also review recent experience with R&D programs to develop lower-cost technologies for SO₂ and NO_x capture at coal-fired power plants. For perspective on projected cost reductions for CO₂ capture we further review past experience in cost trends for SO₂ and NO_x capture systems. The key insight for improved carbon capture technology is that achieving significant cost reductions will require not only a vigorous and sustained level of research and development (R&D), but also a substantial level of commercial deployment, which, in turn, requires a significant market for CO₂ capture technologies. At present such a market does not yet exist. While various incentive programs can accelerate the development and deployment of improved CO₂ capture systems, government actions that significantly limit CO₂ emissions to the atmosphere ultimately are needed to realize substantial and sustained reductions in the future cost of CO₂ capture.     

Options for net zero emissions hydrogen from Victorian lignite. Part 1: Gaseous and liquefied hydrogen

This two-part paper investigates the feasibility of producing export quantities (770 t/d) of blue hydrogen meeting international standards, by gasification of Victorian lignite plus carbon capture and storage (CCS). The study involves a detailed Aspen Plus simulation analysis of the entire production process, taking into account fugitive methane emissions during lignite mining. Part 1 focusses on the resources, energy requirements and greenhouse gas emissions associated with production of gaseous and liquefied hydrogen, while Part 2 focusses on production of ammonia as a hydrogen carrier.In this study, the proposed process comprises lignite mining, lignite drying and milling, air separation unit (ASU), dry-feed entrained flow gasification, gas cooling and cleaning, sour water-gas shift reaction, acid gas removal, pressure swing adsorption (PSA) for hydrogen purification, elemental sulphur recovery, CO₂ compression for transport and injection, hydrogen liquefaction, steam and gas turbines to generate all process power, plus an optional post-combustion CO₂ capture step. High grade waste heat is utilised for process heat and power generation. Three alternative process scenarios are investigated as options to reduce resource utilisation and greenhouse gas emissions: replacing the gas turbine with renewable energy from off-site wind turbines, and co-gasification of lignite with either biomass or biochar. In each case, the specific net greenhouse gas intensity is estimated and compared to the EU Taxonomy specification for sustainable hydrogen.This is the first time that a coal-to-hydrogen study has quantified the greenhouse gas emissions across the entire production chain, including upstream fugitive methane emissions. It is found that both gaseous and liquefied hydrogen can be produced from Victorian lignite, along with all necessary electricity, with specific emissions intensity (SEI) of 2.70 kg CO₂-e/kg H₂ and 2.73 kg CO₂-e/kg H₂, respectively. These values conform to the EU Taxonomy limit of 3.0 kg CO₂-e/kg H₂. This result is achieved using a Selexol™ plant for CO₂ capture, operating at 89.5%–91.7% overall capture efficiency. Importantly, the very low fugitive methane emissions associated with Victorian lignite mining is crucial to the low SEI of the process, making this is a critical advantage over the alternative natural gas or black coal processes.This study shows that there are technical options available to further reduce the SEI to meet tightening emissions targets. An additional post-combustion MDEA CO₂ capture unit can be added to increase the capture efficiency to 99.0%–99.2% and reduce the SEI to 0.3 kg CO₂-e/kg H₂. Emissions intensity can be further reduced by utilising renewable energy rather than co-production of electricity on site. Net zero emissions can then be achieved by co-gasification with ≤1.4 dry wt.% biomass, while a higher proportion of biomass would achieve net-negative emissions. Thus, options exist for production of blue hydrogen from Victorian lignite consistent with a ‘net zero by 2050’ target.     

Performance evaluation of integrated gasification solid oxide fuel cell/gas turbine systems including carbon dioxide capture

In this study, system layouts for integrated gasification solid oxide fuel cell/gas turbine (IG-SOFC/GT) systems were proposed and their performance was comparatively evaluated. A baseline IGCC was simulated, and the calculation models were validated. Based on the IGCC system, two IG-SOFC/GT system layouts with different SOFC thermal management methods were established, and their performance was analyzed. The IG-SOFC/GT systems were found to produce much higher power and better efficiency than the IGCC. With regard to SOFC thermal management, the exit gas recirculation scheme showed better performance than the cathode heat exchange scheme. The impact of CO₂ capture was investigated in both the IGCC and IG-SOFC/GT systems, and the penalties in power output and efficiency due to pre-combustion CO₂ capture were found to be milder in the IG-SOFC/GT systems than in the IGCC. An IG-SOFC/GT system adopting oxy-combustion-based CO₂ capture was proposed, and its thermal efficiency was predicted to be sensibly higher than the system with pre-combustion CO₂ capture. Its net power output was predicted to be less than that of the system with pre-combustion technology, but was still much larger than that of the IGCC with pre-combustion CO₂ capture.     

Techno-economic appraisal of fossil-fuelled power generation systems with carbon dioxide capture and storage

Carbon capture and storage (CCS) facilities coupled to power plants provide a climate change mitigation strategy that potentially permits the continued use of fossil fuels whilst reducing the carbon dioxide (CO₂) emissions. This process involves three basic stages: capture and compression of CO₂ from power stations, transport of CO₂, and storage away from the atmosphere for hundreds to thousands of years. Potential routes for the capture, transport and storage of CO₂ from United Kingdom (UK) power plants are examined. Six indicative options are evaluated, based on ‘Pulverised Coal’, ‘Natural Gas Combined Cycle’, and ‘Integrated (coal) Gasification Combined Cycle’ power stations. Chemical and physical CO₂ absorption capture techniques are employed with realistic transport possibilities to ‘Enhanced Oil Recovery’ sites or depleted gas fields in the North Sea. The selected options are quantitatively assessed against well-established economic and energy-related criteria. Results show that CO₂ capture can reduce emissions by over 90%. However, this will reduce the efficiency of the power plants concerned, incurring energy penalties between 14 and 30% compared to reference plants without capture. Costs of capture, transport and storage are concatenated to show that the whole CCS chain ‘cost of electricity’ (COE) rises by 27-142% depending on the option adopted. This is a significant cost increase, although calculations show that the average ‘cost of CO₂ captured’ is £15/tCO₂ in 2005 prices [the current base year for official UK producer price indices]. If potential governmental carbon penalties were introduced at this level, then the COE would equate to the same as the reference plant, and make CCS a viable option to help mitigate large-scale climate change.