Review of CO2 recovery methods from the exhaust gas of biomass heating systems for safe enrichment in greenhouses

Novel approaches to practice CO₂ enrichment in greenhouses from the exhaust gas of a biomass heating system are reviewed. General CO₂ enrichment benefits for greenhouse plant production are described along with optimal management strategies to reduce fuel consumption while improving benefits. Alternative and renewable fuels for CO₂ enrichment, landfill biogas and biomass, are compared with traditional methods and fuels. Exhaust gas composition is outlined to address the challenges of CO₂ enrichment from biomass combustion and leads to a comparison between combustion and gasification to improve boiler efficiency. In terms of internal modifications to a biomass heating system, syngas combustion, following biomass gasification, presents good potential to achieve CO₂ enrichment. Regarding external modifications to clean the exhaust gas, CO₂ can be extracted from flue gases via membrane separation that has shown a lot of potential for large industries trying to reduce and isolate CO₂ emissions for sequestration. Other research has optimized wet scrubbing systems by extracting SO₂ and NO emissions from flue gases to form ammonium sulphate as a by-product valuable to fertilizer markets. The potential of these techniques are reviewed while future research directions are suggested.     

Optimum conditions for a natural gas combined cycle power generation system based on available oxygen when using biomass as supplementary fuel

Due to the higher oxygen content and lower heating value, the amount of biomass required in a combined cycle, where it is used as supplementary fuel, to meet a given energy demand is such that the biomass consumes almost all of the oxygen remaining from gas turbine combustion process under certain conditions. This situation requires additional air for biomass combustion thus reducing the cycle efficiency and the net work output rate while increasing CO₂ emissions. Three conditions at which the oxygen is completely consumed are identified based on alterations in net fuel utilization. The first condition is linked to fuel utilization, which is observed to be significantly affected by variations in temperatures at three locations in the combined cycle (air temperature entering the gas turbine combustion chamber, gas turbine inlet temperature and HRSG inlet temperatures). The second condition relates to the characteristics of the feedstock (oxygen content of the biomass and heating value of natural gas). The heat loss due to combustion of natural gas and biomass is the third condition that affects oxygen availability. The current work assesses these conditions in order to identify the proper condition at which no additional air is required for supplementary firing of biomass.     

Measurement of laminar burning velocities and Markstein lengths of diluted hydrogen-enriched natural gas

The laminar flame characteristics of natural gas–hydrogen–air–diluent gas (nitrogen/CO₂) mixtures were studied in a constant volume combustion bomb at various diluent ratios, hydrogen fractions and equivalence ratios. Both unstretched laminar burning velocity and Markstein length were obtained. The results showed that hydrogen fraction, diluent ratio and equivalence ratio have combined influence on laminar burning velocity and flame instability. The unstretched laminar burning velocity is reduced at a rate that is increased with the increase of the diluent ratio. The reduction effect of CO₂ diluent gas is stronger than that of nitrogen diluent gas. Hydrogen-enriched natural gas with high hydrogen fraction can tolerate more diluent gas than that with low hydrogen fraction. Markstein length can either increase or decrease with the increase of the diluent ratio, depending on the hydrogen fraction of the fuel.     

Techno-economic assessment on the fuel flexibility of a commercial scale combined cycle gas turbine integrated with a CO2 capture plant

Post-combustion carbon capture is a valuable technology, capable of being deployed to meet global CO₂ emissions targets. The technology is mature and can be retrofitted easily with existing carbon emitting energy generation sources, such as natural gas combined cycles. This study investigates the effect of operating a natural gas combined cycle plant coupled with carbon capture and storage while using varying fuel compositions, with a strong focus on the influence of the CO₂ concentration in the fuel. The novelty of this study lies in exploring the technical and economic performance of the integrated system, whilst operating with different fuel compositions. The study reports the design of a natural gas combined cycle gas turbine and CO₂ capture plant (with 30 wt% monoethanolamine), which were modelled using the gCCS process modelling application. The fuel compositions analysed were varied, with focus on the CO₂ content increasing from 1% to 5%, 7.5% and 10%. The operation of the CO₂ capture plant is also investigated with focus on the CO₂ capture efficiency, specific reboiler duty and the flooding point. The economic analysis highlights the effect of the varying fuel compositions on the cost of electricity as well as the cost of CO₂ avoided. The study revealed that increased CO₂ concentrations in the fuel cause a decrease in the efficiency of the natural gas combined cycle gas turbine; however, rising the CO₂ concentration and flowrate of the flue gas improves the operation of the capture plant at the risk of an increase in the flooding velocity in the column. The economic analysis shows a slight increase in cost of electricity for fuels with higher CO₂ contents; however, the results also show a reduction in the cost of CO₂ avoided by larger margins.     

The European power plant infrastructure—Presentation of the Chalmers energy infrastructure database with applications

This paper presents a newly established database of the European power plant infrastructure (power plants, fuel infrastructure, fuel resources and CO₂ storage options) for the EU25 member states (MS) and applies the database in a general discussion of the European power plant and natural gas infrastructure as well as in a simple simulation analysis of British and German power generation up to the year 2050 with respect to phase-out of existing generation capacity, fuel mix and fuel dependency. The results are discussed with respect to age structure of the current production plants, CO₂ emissions, natural gas dependency and CO₂ capture and storage (CCS) under stringent CO₂ emission constraints.     

Cycle analysis of low and high H2 utilization SOFC/gas turbine combined cycle for CO2 recovery

A major factor in global warming is CO₂ emission from thermal power plants, which burn fossil fuels. One technology proposed to prevent global warming is CO₂ recovery from combustion flue gas and the sequestration of CO₂ underground or near the ocean bed. Solid oxide fuel cell (SOFC) can produce highly concentrated CO₂, because the reformed fuel gas reacts with oxygen electrochemically without being mixed with air in the SOFC. We therefore propose to operate multi-staged SOFCs with high utilization of reformed fuel to obtain highly concentrated CO₂. In this study, we estimated the performance of multi-staged SOFCs considering H₂ diffusion and the combined cycle efficiency of a multi-staged SOFC/gas turbine/CO₂ recovery power plant. The power generation efficiency of our CO₂ recovery combined cycle is 68.5%, whereas the efficiency of a conventional SOFC/GT cycle with the CO₂ recovery amine process is 57.8%.     

Analysis of a feasible polygeneration system for power and methanol production taking natural gas and biomass as materials

Co-utilization of natural gas and biomass is a successful way to make efficient use of them for chemical production and power generation, for biomass is rich in carbon while natural gas is rich in hydrogen. The present paper therefore proposes a new polygeneration system taking biomass and natural gas as materials for methanol production and power generation. The new polygeneration system can achieve the optimal ratio of H₂ to CO for methanol production by adjusting input ratio of natural gas to biomass without any energy penalty. Thus, the suggested system can eliminate CO to H₂ shift process and CO₂ remove process, which can avoid material and energy destruction; however, those processes are otherwise necessary in individual biomass to methanol plant. Moreover, the new system eliminates the CO₂ addition process; however, the addition of CO₂ is necessary in individual natural gas to methanol plant, which causes extra energy penalty. This system combined chemical production and power generation together, in order to achieve the cascaded utilization of chemical and physical energy of natural gas and biomass. In a further way, we investigated the key processes, to maximize the utilization of energy and improve system performance.     

The air membrane-ATR integrated gas turbine power cycle: A method for producing electricity with low CO2 emissions

The air membrane-auto thermal reforming (AM-ATR) gas turbine cycle combines features of the R-ATR power cycle, introduced at the University of Florence, with ceramic, air separation membranes to achieve a novel combined cycle process with fuel decarbonisation and near-zero CO₂ emissions. Within this process, the natural gas fuel is converted to H₂ and CO through the auto thermal reforming process (ATR), i.e. combined partial oxidation and steam methane reforming, within the air separation membrane reactor. In a subsequent process unit, the H₂ content of the reformed fuel is enriched by the well known CO–CO₂ shift reaction. This fuel is then sent to an amine based carbon dioxide removal unit and, finally, to two combustors: the first one is located upstream of the membrane reformer (in order to achieve the required working temperature) and the second one is downstream of the membrane to reach the desired turbine inlet temperature (TIT).The main advantage of the proposed concept over other decarbonisation processes is the coupling of the membrane and the ATR reactor. This coupling greatly reduces the mass flow of syngas with respect to the air blown ATR contained in the previously proposed R-ATR, thus lowering the size of the syngas treatment section. Furthermore, as the oxygen production is integrated at high temperatures in the power cycle, the efficiency penalty of producing oxygen is much smaller than for the traditional cryogenic oxygen separation. The main advantages over other integrated GT-membrane concepts are the lower membrane operating temperature, lower levels of required air separation at high partial pressure driving forces (leading to lower membrane surface areas) and the possibility to achieve a higher TIT with top firing without increasing CO₂ emissions. When compared to power plants with tail end CO₂ separation, the CO₂ removal process treats a gas at pressure and with a significantly higher CO₂ concentration than that of gas turbine exhausts, which allows a compact carbon dioxide removal unit with a lower energy penalty.Starting from the same basis, various configurations were considered and optimised, all of which targeted a 65 MW power output combined cycle. The efficiency level achieved is around 45% (including recompression of the separated CO₂), which is roughly 10% less than the reference GT-CC plant (without CO₂ removal). A significant part of the efficiency penalty (4.3–5.6% points) is due to the fuel reforming, whereas further penalties come from the recompression units, loss of working fluid through the expander and the steam extracted for the ATR reactor and CO₂ separation. The specific CO₂ emissions of the MCM-ATR are about 120 kg CO₂/kWh, representing 30% of the emissions without CO₂ removal. This may be reduced to 10–15% with a better design of the shift reactors and the CO₂ removal unit. Compared to other concepts with air membrane technology, such as the AZEP concept, the efficiency loss is much greater when used for fuel de-carbonisation than for previous integration options.     

Cost-effective CO2 emission reduction through heat,power and biofuel production from woody biomass: A spatially explicit comparison of conversion technologies

Bioenergy is regarded as cost-effective option to reduce CO₂ emissions from fossil fuel combustion. Among newly developed biomass conversion technologies are biomass integrated gas combined cycle plants (BIGCC) as well as ethanol and methanol production based on woody biomass feedstock. Furthermore, bioenergy systems with carbon capture and storage (BECS) may allow negative CO₂ emissions in the future. It is still not clear which woody biomass conversion technology reduces fossil CO₂ emissions at least costs. This article presents a spatial explicit optimization model that assesses new biomass conversion technologies for fuel, heat and power production and compares them with woody pellets for heat production in Austria. The spatial distributions of biomass supply and energy demand have significant impact on the total supply costs of alternative bioenergy systems and are therefore included in the modeling process. Many model parameters that describe new bioenergy technologies are uncertain, because some of the technologies are not commercially developed yet. Monte-Carlo simulations are used to analyze model parameter uncertainty. Model results show that heat production with pellets is to be preferred over BIGCC at low carbon prices while BECS is cost-effective to reduce CO₂ emissions at higher carbon prices. Fuel production – methanol as well as ethanol – reduces less CO₂ emissions and is therefore less cost-effective in reducing CO₂ emissions.     

High quality product gas from biomass steam gasification combined with torrefaction and carbon dioxide capture processes

Gasification is currently recognized as a mature technology to convert biomass into useful and versatile product gas for further energy and fuel applications. However, there are some remaining problems relating to the process operation and process efficiency due to inherent properties of biomass feedstock such as high moisture content, low energy density and high oxygen content. Strategies to improve the efficiency of biomass gasification as well as the quality of product gas are thus required. For this purpose, a combined process of torrefaction, gasification, and carbon dioxide capture is developed and simulated in a commercial simulator to investigate the performance of a biomass gasification coupled with a pre-treatment and a post-treatment processes. The results show that the quality of product gas is enhanced when combining gasification with a torrefaction and a CO₂ capture processes. The heating value of the product gas and the cold gas efficiency are both increased with additional torrefaction. The CO₂ capture process using monoethanolamine offers a CO₂ removal efficiency of about 83% and consequently increase the product gas heating value up to 27%.     

Modeling fuel NOx formation from combustion of biomass-derived producer gas in a large-scale burner

This study investigates the characteristics of fuel NO_x formation resulting from the combustion of producer gas derived from biomass gasification using different feedstocks. Common industrial burners are optimized for using natural gas or coal-derived syngas. With the increasing demand in using biomass for power generation, it is important to develop burners that can mitigate fuel NO_x emissions due to the combustion of ammonia, which is the major nitrogen-containing species in biomass-derived gas. In this study, the combustion process inside the burner is modeled using computational fluid dynamics (CFD) with detailed chemistry. A reduced mechanism (36 species and 198 reactions) is developed from GRI 3.0 in order to reduce the computation time. Combustion simulations are performed for producer gas arising from different feedstocks such as wood gas, wood + 13% DDGS (dried distiller grain soluble) gas and wood + 40% DDGS gas and also at different air equivalence ratios ranging from 1.2 to 2.5. The predicted NO_x emissions are compared with the experimental data and good levels of agreement are obtained. It is found out that NO_x is very sensitive to the ammonia content in the producer gas. Results show that although NO–NO₂ interchanges are the most prominent reactions involving NO, the major NO producing reactions are the oxidation of NH and N at slightly fuel rich conditions and high temperature. Further analysis of results is conducted to determine the conditions favorable for NO_x reduction. The results indicate that NO_x can be reduced by designing combustion conditions which have fuel rich zones in most of the regions. The results of this study can be used to design low NO_x burners for combustion of gas mixtures derived from gasification of biomass. One suggestion to reduce NO_x is to produce a diverging flame using a bluff body in the flame region such that NO generated upstream will pass through the fuel rich flame and be reduced.     

Pathways to low-cost clean hydrogen production with gas switching reforming

Gas switching reforming (GSR) is a promising technology for natural gas reforming with inherent CO₂ capture. Like conventional steam methane reforming (SMR), GSR can be integrated with water-gas shift and pressure swing adsorption units for pure hydrogen production. The resulting GSR-H2 process concept was techno-economically assessed in this study. Results showed that GSR-H2 can achieve 96% CO₂ capture at a CO₂ avoidance cost of 15 $/ton (including CO₂ transport and storage). Most components of the GSR-H2 process are proven technologies, but long-term oxygen carrier stability presents an important technical uncertainty that can adversely affect competitiveness when the material lifetime drops below one year. Relative to the SMR benchmark, GSR-H2 replaces some fuel consumption with electricity consumption, making it more suitable to regions with higher natural gas prices and lower electricity prices. Some minor alterations to the process configuration can adjust the balance between fuel and electricity consumption to match local market conditions. The most attractive commercialization pathway for the GSR-H2 technology is initial construction without CO₂ capture, followed by simple retrofitting for CO₂ capture when CO₂ taxes rise, and CO₂ transport and storage infrastructure becomes available. These features make the GSR-H2 technology robust to almost any future energy market scenario.     

System study of carbon dioxide (CO2) capture in bio-based motor fuel production

A number of different technologies for producing renewable motor fuels have been studied; some effects of applying carbon dioxide (CO₂) capture to the production of renewable motor fuels are described in this paper. Some of the technologies studied are well suited for CO₂ capture. However, it is shown that the advantages with CO₂ capture for these technologies are not enough to offset their shortcomings described in previous studies, which show that the largest CO₂ reduction from biomass in Sweden may be achieved by producing fuel pellets for coal substitution or using the biomass in combined heat and power plants. A conclusion of the present paper is that even with CO₂ capture added to the respective technology, it is inefficient to use renewable resources for motor fuel production if the aim is to achieve as high CO₂ emission reduction as possible per input of biomass. Therefore, the large Swedish subsidies of the production of motor fuels appear sub-optimal, also when the possibility of CO₂ capture is considered. Nevertheless, incorporating CO₂ capture in the production of renewable motor fuels from biomass might be a cost-effective way of reducing CO₂ emissions.     

Effects on global CO<Subscript>2</Subscript> emissions when substituting LPG with bio-SNG as fuel in steel industry reheating furnaces—the impact of different perspectives on CO<Subscript>2</Subscript> assessment

The iron and steel industry is the second largest user of energy in the world industrial sector and is currently highly dependent on fossil fuels and electricity. Substituting fossil fuels with renewable energy in the iron and steel industry would make an important contribution to the efforts to reduce emissions of CO₂. However, different approaches to assessing CO₂ emissions from biomass and electricity use generate different results when evaluating how fuel substitution would affect global CO₂ emissions. This study analyses the effects on global CO₂ emissions when substituting liquefied petroleum gas with synthetic natural gas, produced through gasification of wood fuel, as a fuel in reheating furnaces at a scrap-based steel plant. The study shows that the choice of system perspective has a large impact on the results. When wood fuel is considered available for all potential users, a fuel switch would result in reduced global CO₂ emissions. However, applying a perspective where wood fuel is seen as a limited resource and alternative use of wood fuel is considered, a fuel switch could in some cases result in increased global CO₂ emissions. As an example, in one of the scenarios studied, a fuel switch would reduce global CO₂ emissions by 52 ktonnes/year if wood fuel is considered available for all potential users, while seeing wood fuel as a limited resource implies, in the same scenario, increased CO₂ emissions by 70 ktonnes/year. The choice of method for assessing electricity use also affects the results.     

Detailed study of the impact of co-utilization of biomass in a natural gas combined cycle power plant through perturbation analysis

Co-utilization of fossil fuels and biomass is a successful way to make efficient use of biomass for power production. When replacing only a limited amount of fossil fuel by biomass, measurements of net output power and input fuel rates will however not suffice to accurately determine the marginal efficiency of the newly introduced alternative fuel. The present paper therefore proposes a technique to determine the marginal biomass efficiency with more accuracy. The process simulation model for co-utilization of natural gas and a small perturbing fraction of biomass in an existing combined cycle plant (500 MW_th Drogenbos, Belgium) is taken as case study. In this particular plant, biomass is introduced into the cycle as fuel for a primary steam reforming process of the input natural gas.     

Blue sky mining: Strategy for a feasible transition in emerging countries from natural gas to hydrogen

Natural gas is often considered a transition fuel to a deep decarbonized world. However, for this to happen, new technologies should be fostered, among which a natural gas-based H₂ industry can become a key-option. This study tests the hypothesis that the development of a natural gas-based H₂ industry equipped with CO₂ capture can monetize natural gas remaining resources, mitigate CO₂ emissions and facilitate the transition to the renewable energy-based H₂. To do that, this study evaluates a stepwise strategy for setting up the development of H2, departing from the idle capacity in the existing natural gas industry, to progressively create a H₂ independent supply. Findings indicated that this strategy can be feasible, according to the case study assessed at relatively moderate crude oil prices. Nevertheless, CO₂ storage can become a constraint to deal with the co-produced CO₂ from the steam methane reforming units. Therefore, it is worth developing storage options.     

The pollutant discharge improvement by introducing HHO gas into biomass boiler

Biomass fuel has been widely concerned because its net CO₂ emission is close to zero. Biomass boilers are known to have lower pollutant emissions than fossil fuel boilers, but in some applications, they also release high-level CO and NO. We developed a medium-sized hydrogen and oxygen (HHO) generator, with high energy conversion rate and adjustable output gas. The HHO gas was then introduced into a biomass hot air generator for mixed combustion. The experimental results showed that based on the electricity consumption of gas production and biomass fuel price, the total cost during preheating reduced. In addition, the average concentrations of CO, NO and smoke decreased by 93.0%, 22.5% and 80%, respectively. Integration of biomass fuel and HHO gas can effectively reduce pollutant emissions and save fuel, especially in areas rich in renewable energy.     

Hydrogen rich fuel gas production by gasification of wet biomass using a CO2 sorbent

Hydrogen rich fuel gas production by gasification of wet biomass accompanied by CO₂ absorption is proposed. The paper addressed this topic, and experiments were conducted to investigate the effects of the moisture content (M), the molar ratio of Ca(OH)₂ to carbon in the biomass ([Ca]/[C]) and the reactor temperature (T) on hydrogen production and CO₂ absorption by CaO. Measurement of the calcium compounds in solid residues was carried out with XRD and SEM. The results show that directly gasifying of wet biomass not only favors hydrogen production but also promotes CO₂ absorption by CaO. For the experiment with wet biomass (M = 0.90), the H₂ yield is increased by 51.5% while the CO₂ content is decreased by 28.4% than that for experiments with dry biomass (M = 0.09). CaO plays the dual role of catalyst and sorbent. It is noteworthy that CaO reveals a stronger effect on the water gas shift reaction than on the steam reforming of methane. The increase of the reactor temperature contributes to produce more H₂, but goes against CO₂ absorption by CaO. XRD spectrum and SEM image of the solid residues further confirmed that high temperature is unfavorable to CO₂ absorption by CaO. For the new method, the optimal operating temperature is in the 923–973 K range.     

Capturing CO2 in flue gas from fossil fuel-fired power plants using dry regenerable alkali metal-based sorbent

CO₂ capture and storage (CCS) has received significant attention recently and is recognized as an important option for reducing CO₂ emissions from fossil fuel combustion. A particularly promising option involves the use of dry alkali metal-based sorbents to capture CO₂ from flue gas. Here, alkali metal carbonates are used to capture CO₂ in the presence of H₂O to form either sodium or potassium bicarbonate at temperatures below 100 °C. A moderate temperature swing of 120–200 °C then causes the bicarbonate to decompose and release a mixture of CO₂/H₂O that can be converted into a “sequestration-ready” CO₂ stream by condensing the steam. This process can be readily used for retrofitting existing facilities and easily integrated with new power generation facilities. It is ideally suited for coal-fired power plants incorporating wet flue gas desulfurization, due to the associated cooling and saturation of the flue gas. It is expected to be both cost effective and energy efficient.     

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.