Chilled ammonia process for CO2 capture

The chilled ammonia process absorbs the CO₂ at low temperature (2–10 °C). The heat of absorption of carbon dioxide by ammonia is significantly lower than for amines. In addition, degradation problems can be avoided and a high carbon dioxide capacity is achieved. Hence, this process shows good perspectives for decreasing the heat requirement. However, a scientific understanding of the processes is required. The thermodynamic properties of the NH₃–CO₂–H₂O system were described using the extended UNIQUAC electrolyte model developed by Thomsen and Rasmussen in a temperature range from 0 to 110 °C and pressure up to 100 bars. The results show that solid phases consisting of ammonium carbonate and bicarbonate are formed in the absorber. The heat requirements in the absorber and in the desorber have been studied. The enthalpy calculations show that a heat requirement for the desorber lower than 2 GJ/ton CO₂ can be reached.     

Oxygen supply for oxyfuel CO2 capture

This paper presents the results of a study to develop Air Products’ air separation unit (ASU) offerings for oxyfuel coal CO₂ capture projects. A scalable “reference plant” concept is described to match particular sizes of power generation equipment, taking into account factors such as safety, reliability, operating flexibility, efficiency, and low capital cost. We describe the selection of a process cycle to exploit the low purity requirements, as well as the options for compression machinery and drivers as the scale of the plant increases and the sizes of referenced equipment limit the possibilities. We also explore integration with other elements of the system, such as preheating condensate or heating and expanding pressurised nitrogen. In addition, we consider how the ASU affects the flexibility of the oxyfuel system and discuss how its power consumption can be reduced during periods of high power demand. Finally, the advantages and disadvantages of different execution strategies for air separation unit projects are discussed, as well as alternative commercial models for the supply of oxygen.     

Modeling CO2 capture with aqueous monoethanolamine

Hilliard completed several thermodynamic models in Aspen Plus^® for modeling CO₂ removal with amine solvents, including MEA–H₂O–CO₂. This solvent was selected to make a system model for CO₂ removal by absorption/stripping. Both the absorber and the stripper used RateSep? to rigorously calculate mass transfer rates. The accuracy of the new model was assessed using a recent pilot plant run with 35 wt.% (9 m) MEA. Absorber loading and removal were predicted within 6%, and the temperature profile was approached within 5 °C. An average 3.8% difference between measured and calculated values was achieved in the stripper. A three-stage flash configuration which efficiently utilizes solar energy was developed. It reduces energy use by 6% relative to a simple stripper. Intercooling was used to reach 90% removal in the absorber at these optimized conditions.     

CO2 capture for refineries,a practical approach

This paper evaluates the opportunities and associated costs for post-combustion capture at a world-scale complex refinery. It is concluded that it is technically feasible to apply post-combustion capture at such a refinery. The costs for capture and sequestration from a gasifier are calculated to be lowest at about 30 Euro per ton; this process currently already produces a concentrated CO₂ stream. Next, the CO₂ source most suited for capture appears to be a combined stack, but there are a number of other sources that may be targeted at comparable costs. In total these sources may form about 40% of the overall refinery emissions. Our evaluations show the costs of capture from such sources based on available amine technology will be in the range of 90–120 Euro per ton, which is about 3–4 times higher than the current carbon trading values. The capture of CO₂ from a large amount of smaller CO₂ sources will bring along even much higher costs. A high-level study of the CO₂ emissions profile of a number of Shell refineries shows that, typically, up to 50% of the emitted CO₂ may be captured at similar costs. About 10–20% of concentrated CO₂ associated with hydrogen manufacturing may be captured at lower costs. The remainder of emitted dilute CO₂ will bring along significantly higher costs. Based on this study, it is concluded for the justification of the implementation of post-combustion capture at refineries, either a significant increase in carbon trading values, mandatory regulations, or a major technological break-through is required.     

Co-production of hydrogen and electricity with CO2 capture

Electricity and hydrogen can be used as energy carriers to reduce emissions of CO₂ from small and mobile energy users. One of the most promising technologies for the production of electricity and hydrogen with low CO₂ emissions is coal gasification with CO₂ capture and storage. Performance and cost data are presented for plants which produce electricity and hydrogen alone and plants which co-produce both of these energy carriers. The co-production plants include plants which produce a fixed ratio of hydrogen to electricity and plants which are able to vary the ratio while continuing to operate the gasification and CO₂ capture parts of the plant at full load. The paper also assesses the ability of these types of plants to satisfy the varying demands for hydrogen and electricity in future energy supply systems. The lowest cost option for the scenarios assessed in the paper is the use of flexible co-production plants with underground buffer storage of hydrogen.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

Prospects for cost-effective post-combustion CO2 capture from industrial CHPs

Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50–200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020–2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline.The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41–44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33–36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46–50 €/tCO₂ avoided short term, 30–35 €/tCO₂ avoided mid-term).     

Carbonic anhydrase-facilitated CO2 absorption with polyacrylamide buffering bead capture

A novel CO₂ separation concept is described wherein the enzyme carbonic anhydrase (CA) is used to increase the overall rate of CO₂ absorption after which hydrated CO₂ reacts with regenerable amine-bearing polyacrylamide buffering beads (PABB). Following saturation of the material's immobilized tertiary amines, CA-bearing carrier water is separated and recycled to the absorption stage while CO₂-loaded material is thermally regenerated. Process application of this concept would involve operation of two or more columns in parallel with thermal regeneration with low-pressure steam taking place after the capacity of a column of amine-bearing polymeric material was exceeded. PABB CO₂-bearing capacity was evaluated by thermogravimetric analysis (TGA) for beads of three acrylamido buffering monomer ingredient concentrations: 0 mol/kg bead, 0.857 mol/kg bead, and 2 mol/kg bead. TGA results demonstrate that CO₂-bearing capacity increases with increasing PABB buffering concentration and that up to 78% of the theoretical CO₂-bearing capacity was realized in prepared PABB samples (0.857 mol/kg recipe). The highest observed CO₂-bearing capacity of PABB was 1.37 mol of CO₂ per kg dry bead. TGA was also used to assess the regenerability of CO₂-loaded PABB. Preliminary results suggest that CO₂ is partially driven from PABB samples at temperatures as low as 55 °C, with complete regeneration occurring at 100 °C. Other physical characteristics of PABB are discussed. In addition, the effectiveness of bovine carbonic anhydrase for the catalysis of CO₂ dissolution is evaluated. Potential benefits and drawbacks of the proposed process are discussed.     

CO2 capture by adsorption: Materials and process development

Vacuum swing adsorptive (VSA) capture of CO₂ from flue gas and related process streams is a promising technology for greenhouse gas mitigation. Although early reports suggested that VSA was problematic and expensive, through the application of more logical process configurations that are appropriately coupled to the composition of the feed and product gas streams, we can now refute this early assertion. Improved cycle designs coupled with tighter temperature control are also helping to optimise performance for CO₂ separation. Simultaneously, new adsorbent materials are being developed. These separate CO₂ by selective (acid-base) reaction with surface bound amine groups (chemisorption), rather than on the basis of non-bonding interactions (physisorption). This report describes some of these recent developments from our own laboratories and points to synergies that are anticipated as a result of combining these improvements in adsorbent properties and VSA process cycles.     

Thermodynamic analysis on post-combustion CO2 capture of natural-gas-fired power plant

A chemical absorption, post-combustion CO₂ capture unit is simulated and an exergy analysis has been conducted, including irreversibility calculations for all process units. By pinpointing major irreversibilities, new proposals for efficient energy integrated chemical absorption process are suggested. Further, a natural-gas combined-cycle power plant with a CO₂ capture unit has been analyzed on an exergetic basis. By defining exergy balances and black-box models for plant units, investigation has been made to determine effect of each unit on the overall exergy efficiency. Simulation of the chemical absorption plant was done using UniSim Design software with Amines Property Package. For natural-gas combined-cycle design, GT PRO software (Thermoflow, Inc.) has been used. For exergy calculations, spreadsheets are created with Microsoft Excel by importing data from UniSim and GT PRO. Results show the exergy efficiency of 21.2% for the chemical absorption CO₂ capture unit and 67% for the CO₂ compression unit. The total exergy efficiency of CO₂ capture and compression unit is 31.6%.     

Gas conditioning—The interface between CO2 capture and transport

Gas conditioning is commonly referred to as the required processing for a produced natural gas to achieve transport and sales specifications. In this paper, gas conditioning as the processing required in the interface between CO₂ capture and transport is studied for nine different natural gas fired power plant concepts and three different CO₂ transport processes. Conditioning processes for both pipeline and ship transport are described and an enhanced process for volatile removal is developed. The energy requirement for the conditioning processes is normally between 90 and 120 kWh/tonne CO₂; however, this depends on the pressure and composition of the captured CO₂-rich stream. The loss of CO₂ in the water purge is small for most capture processes. The waste streams from the gas conditioning processes can contain large amounts of CO₂ and should therefore be further processed or reintroduced at an appropriate point upstream in the capture or gas conditioning process if possible. The integration benefit may vary depending on the composition of the CO₂-rich stream. It could be particularly interesting for processes with “innovative reactors” (membranes, sorbents, chemical looping) to integrate CO₂ capture and gas conditioning.     

Optimization of a membrane process for CO2 capture in the steelmaking industry

Three different types of membranes were experimentally evaluated for CO₂ recovery from blast furnace effluents: semi-commercial adsorption selective carbon membranes, in-house tailored carbon molecular sieving membranes, and fixed site carrier (FSC) membranes with amine groups in the polymer backbone for active transport of CO₂. In the single gas experiments the FSC membranes showed superior selectivity for CO₂ over the other relevant gases (CO, N₂ and H₂) and high CO₂ permeance (productivity). In addition, it is easy to process and handle, relatively inexpensive to produce and the water in the feed gas is an advantage rather than a problem, since the membrane must be humidified during operation. Based on these experiments a simulation study of a full scale process was performed. The technology showed notable low energy cost, even when converted to the thermal equivalent. Total costs for the CO₂ recovery unit (CO₂ prepared for pipeline transport) were estimated to be in the range 15.0–17.5 €/tonnes CO₂.     

Techno-economic study of CO2 capture from natural gas based hydrogen plants

Canadian oil sands are considered to be the second largest oil reserves in the world. However, the upgrading of bitumen from oil sands to synthetic crude oil (SCO) requires nearly ten times more hydrogen (H₂) than conventional crude oils. The current H₂ demand for oil sands operations is met mostly by steam reforming of natural gas (SMR). The future expansion of oil sands operations is likely to quadruple the demand of H₂ for oil sand operations in the next decade.This paper presents modified process schemes that capture CO₂ at minimum energy penalty in modern SMR plants. The approach is to simulate a base case H₂ plant without CO₂ capture and then look for the best operating conditions that minimize the energy penalty associated with CO₂ capture while maximizing H₂ production. The two CO₂ capture schemes evaluated in this study include a membrane separation process and the monoethanolamine (MEA) absorption process. A low energy penalty is observed when there is lower CO₂ production and higher steam production. The process simulation results show that the H₂ plant with CO₂ capture has to be operated at lower steam to carbon ratio (S/C), higher inlet temperature of the SMR and lower inlet temperatures for the water gas-shift (WGS) converters to attain lowest energy penalty. Also it is observed that both CO₂ capture processes, the membrane process and the MEA absorption process, are comparable in terms of energy penalty and CO₂ avoided when both are operated at conditions where lowest energy penalty exists.     

CO2 capture from combined cycles integrated with Molten Carbonate Fuel Cells

In this paper Molten Carbonate Fuel Cells (MCFCs) are considered for their potential application in carbon dioxide separation when integrated into natural gas fired combined cycles. The MCFC performs on the anode side an electrochemical oxidation of natural gas by means of CO₃^2? ions which, as far as carbon capture is concerned, results in a twofold advantage: the cell removes CO₂ fed at the cathode to promote carbonate ion transport across the electrolyte and any dilution of the oxidized products is avoided.The MCFC can be “retrofitted” into a combined cycle, giving the opportunity to remove most of the CO₂ contained in the gas turbine exhaust gases before they enter the heat recovery steam generator (HRSG), and allowing to exploit the heat recovery steam cycle in an efficient “hybrid” fuel cell + steam turbine configuration. The carbon dioxide can be easily recovered from the cell anode exhaust after combustion with pure oxygen (supplied by an air separation unit) of the residual fuel, cooling of the combustion products in the HRSG and water separation. The resulting power cycle has the potential to keep the overall cycle electrical efficiency approximately unchanged with respect to the original combined cycle, while separating 80% of the CO₂ otherwise vented and limiting the size of the fuel cell, which contributes to about 17% of the total power output so that most of the power capacity relies on conventional low cost turbo-machinery. The calculated specific energy for CO₂ avoided is about 4 times lower than average values for conventional post-combustion capture technology. A sensitivity analysis shows that positive results hold also changing significantly a number of MCFC and plant design parameters.     

Life cycle modelling of fossil fuel power generation with post-combustion CO2 capture

Due to its compatibility with the current energy infrastructures and the potential to reduce CO₂ emissions significantly, CO₂ capture and geological storage is recognised as one of the main options in the portfolio of greenhouse gas mitigation technologies being developed worldwide. The CO₂ capture technologies offer a number of alternatives, which involve different energy consumption rates and subsequent environmental impacts. While the main objective of this technology is to minimise the atmospheric greenhouse gas emissions, it is also important to ensure that CO₂ capture and storage does not aggravate other environmental concerns. This requires a holistic and system-wide environmental assessment rather than focusing on the greenhouse gases only. Life Cycle Assessment meets this criteria as it not only tracks energy and non-energy-related greenhouse gas releases but also tracks various other environmental releases, such as solid wastes, toxic substances and common air pollutants, as well as the consumption of other resources, such as water, minerals and land use. This paper presents the principles of the CO₂ capture and storage LCA model developed at Imperial College and uses the pulverised coal post-combustion capture example to demonstrate the methodology in detail. At first, the LCA models developed for the coal combustion system and the chemical absorption CO₂ capture system are presented together with examples of relevant model applications. Next, the two models are applied to a plant with post-combustion CO₂ capture, in order to compare the life cycle environmental performance of systems with and without CO₂ capture. The LCA results for the alternative post-combustion CO₂ capture methods (including MEA, K⁺/PZ, and KS-1) have shown that, compared to plants without capture, the alternative CO₂ capture methods can achieve approximately 80% reduction in global warming potential without a significant increase in other life cycle impact categories. The results have also shown that, of all the solvent options modelled, KS-1 performed the best in most impact categories.     

Study on CO2 capture using dry potassium-based sorbents through orthogonal test method

The effect of reaction conditions on the carbonation characteristics of K₂CO₃ calcined from KHCO₃ was investigated with a pressurized thermogravimetric apparatus. Results show that the conversion rate decreased as the reaction temperature and pressure increased, and the effect of CO₂ and H₂O concentration is little. The mean reaction rate maintained constant of 3%/min. The maximum reaction rate increased as the temperature and H₂O concentration increased, and the pressure decreased. The reaction temperature and pressure are the key factors, and it is important to control those carefully for this technique. The optimum reaction condition is 60 °C, 18% CO₂, 18% H₂O, and 1 atm. K₂CO₃ calcined from KHCO₃ showed excellent CO₂ capture capability in this condition.     

Novel lithium-based sorbents from fly ashes for CO2 capture at high temperatures

In this work several Li₄SiO₄-based sorbents from fly ashes for CO₂ capture at high temperatures have been developed. Three fly ash samples were collected and subjected to calcination at 950 °C in the presence of Li₂CO₃. Both pure Li₄SiO₄ and fly ash-based sorbents were characterised and tested for CO₂ sorption at different temperatures between 400 and 650 °C and adding different amounts of K₂CO₃ (0–40 mol%). To examine the sorbents performance, multiple CO₂ sorption/desorption cycles were carried out. The temperature and the presence of K₂CO₃ strongly affect the CO₂ sorption capacity for the sorbents prepared from fly ashes. When the sorption temperature increases by up to 600 °C both the CO₂ sorption capacity and the sorption rate increase significantly. Moreover when the amount of K₂CO₃ increases, the CO₂ sorption capacity also increases. At optimal experimental conditions (600 °C and 40 mol% K₂CO₃), the maximum CO₂ sorption capacity for the sorbent derived from fly ash was 107 mg CO₂/g sorbent. The Li₄SiO₄-based sorbents can maintain its original capacity during 10 cycle processes and reach the plateau of maximum capture capacity in less than 15 min, while pure Li₄SiO₄ presents a continual upward tendency for the 15 min of the capture step and attains no equilibrium capacity.     

Informed and uninformed public opinions on CO2 capture and storage technologies in the Netherlands

Two research methods were used in this study to analyze the awareness and perception of the Dutch general public regarding Carbon dioxide Capture and Storage (CCS). In an Information-Choice Questionnaire (ICQ), a representative sample of the Dutch public (n = 995) was provided with all information on attributes of six CCS options, which experts deemed necessary to come to well-considered and well-informed opinions. A traditional questionnaire was used simultaneously (n = 327) to study uninformed evaluations of these technologies. The results showed that the Dutch public is mostly unaware of CCS and has little knowledge about how current energy use causes global warming. Uninformed respondents are still inclined to give their opinion however, which results in unpredictive, easily changeable opinions. ICQ respondents who processed information on attributes of CCS options were likely to base their option evaluations on this information, though not entirely. All in all, the results of the ICQ suggest that, after processing information deemed necessary by experts, Dutch people reluctantly agree with large scale implementation of each of the six CCS options.     

Assessing the value of CO2 capture ready in new-build pulverised coal-fired power plants in China

Making new plants CO₂ capture ready (CCR) would enable them to retrofit to capture CO₂ at a later date at lower cost when the appropriate policy and/or economic drivers are in place. In order to understand the economic value and investment characteristics of making new plants CCR in China, a typical 600 MW pulverised coal-fired ultra-supercritical power plant, locating in Guangdong province, was examined. Combined with an engineering assessment, costs were estimated for different CCR scenarios. To analyze CCR investment opportunities, the paper applies a cash flow model for valuing capture options and CCR investment. Results were obtained by Monte-Carlo simulation, based on engineering surveys and an IEA GHG CCR study, as well as plant performance information and expert projections on carbon prices, coal prices and electricity prices.CCR investments are justified by factors such as higher retrofitting probabilities, lower early closure probabilities and fair economic return. However, the economic case for CCR largely depends on two factors: (a) whether the original plant is retrofittable without CCR; and (b) the type of investments made, for example, investments essential to CCR tend to be more economic than additional non-essential CCR features such as clutched low pressure turbines. The carbon price and discount rate were found to have significant impacts on the economics of CCR. Overall, it appears that the value of the ‘capture options’ that CCR generates for retrofitting CCS is significant, and so could justify a modest CCR investment, even assuming the original plant is retrofittable without CCR. It was also found the value of CCR might be significantly understated if the range of potential retrofitting dates is artificially constrained.