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1. Introduction

With increased awareness of climate change and the ongoing effort to reduce greenhouse gas emissions, solutions are sought for replacement of fossil fuels by renewable ones [1,2]. Biomass and various wastes are perceived as promising materials to produce energy, fuels, and chemicals [3,4,5,6]. Technologies facilitating production of electric energy in a more efficient way compared to biomass- and waste-based steam and power plants [7] include co-combustion in fossil fuel power plants [8,9], gasification, and pyrolysis [10,11,12]. While the latter two still represent a substantial challenge regarding the feed properties [13,14], key equipment design, and operation, co-firing offers a less costly and simpler option for fossil fuel consumption reduction in the heat and power production sector [15,16].

Biomass and waste co-combustion has been intensely researched in the last decade. Pilot and full scale systems studies conducted several decades ago [17,18,19] continue to be published [20,21], but they are more recently accompanied by laboratory experiments employing drop tube furnaces [22,23,24], thermogravimetric analyses (TGA) [25,26,27], and other laboratory equipment [28,29]. Experience with co-combustion systems operation are reported in the USA [30,31], Europe [32], as well as other parts of the world [33], generally claiming reduction in CO2 and other greenhouse gases emissions [34] with only minor changes in co-fired power plants and utility boilers thermal efficiencies [35]. Operational issues including the propensity for boiler slagging [36], fouling, and corrosion [15] are still not tackled sufficiently, though. Improved understanding of these aspects [37,38,39,40] aids the assessment of co-combustion sustainability. Greenhouse gases (GHG) emissions [41,42,43] and other emission [44,45] trends with varying biomass type and share and process conditions are studied and evaluated. New biomass and waste types are studied [46,47,48], searching for optimal co-combustion conditions, exploring material synergies [49] and improved properties and utilization of produced ash [50,51]. Feed storage and pretreatment [52] is another important factor influencing the co-combustion economics. Despite these challenges, co-combustion of biomass, combustible industrial byproducts, and wastes is acknowledged as a feasible part of the near- and mid-term environmental strategy of the European Union (EU) [2,53]. Performed techno-economic studies [54,55,56] contribute to the co-combustion applicability assessment. The modeling and computational approach to various scale systems performance is more widespread [57,58,59], which contributes to the understanding of co-combustion systems’ behavior and interactions.

These trends document the need for a review of the biomass and waste co-combustion technology state of the art, recent advances therein, and the challenges it faces. Paper organization is as follows: First, biomass availability is assessed, followed by a survey on biomass and fossil fuel basic properties. Next, relevant biomass pretreatment techniques are discussed. Alternative co-combustion technologies are briefly presented, and a separate part is dedicated to co-combustion equipment. Parts dealing with combustion products properties (ash, flue gases) and the related fouling, slagging, and corrosion issues as well as with harmful emissions and process modification possibilities for their alleviation follow. Future challenges are debated briefly, and a short Conclusions part ends the review. 2. Biomass and Waste Availability, Co-Combustion Technical Potential, Biomass Supply Chain, and CO2 LCA

A review on biomass co-combustion in coal power plants in the EU by Hansson et al. (2009) [9] identified its technical potential as 520 to 940 PJ/year depending on the coal boilers age, below 40 or below 30 years, considered for co-combustion. This biomass potential in conversion to power production represented less than 5% of gross national electricity production in most EU countries. Technical potential increase of around 25% to 40% can be expected with the facilities under construction or planned to be built in the near future. With the prospect of old coal power plants shutdown, the co-combustion potential decreased on the other hand, and it should be close to zero in 2040. Overall potential of residual and waste biomass in the EU-27 for the use in energy production sector exceeded 6000 PJ/year as concluded by both Hansson et al. (2009) [9] and Alakangas et al. (2012) [60], with woody residues, firewood, and herbaceous and fruit biomass representing more than two thirds of the total biomass [60]. More recent studies estimated this potential as high as 11,500 PJ/year in the EU-28 + Western Balkan countries [61], while solely in Germany, the annually available unused biomass amounted up to 30 to 47 million tons [62], representing roughly 250 to 400 PJ/year of energy content.

McIlveen-Wright et al. (2011) [54] simulated a range of power plants by the European Coal Liquefaction Process Simulation and Evaluation (ECLIPSE) simulation software package in different co-combustion configurations to estimate and compare their breakeven electricity selling price (BESP), with a 600 MWe supercritical pulverized coal-fired power plant with flue gas desulfurization plant serving as a benchmark. Due to considered fuel prices, all co-combustion options suffered from higher BESP; its difference amounted to around 10 $/MWh for large scale (≥250 MWe) systems with 20% biomass share but exceeded 50 $/MWh for small scale (≤25 MWe) systems with over 50% biomass share. The CO2 credit needed to reach the same BESP ranges from 50 to 500 $/t CO2, depending on system size and biomass share.

Agbor et al. (2016) [55] studied 60 biomass co-combustion scenarios with coal and natural gas in pulverized coal boilers and natural gas (NG) fired combined cycles (CC). A detailed economic analysis was presented yielding incremental and levelized electricity cost. Both parameters increased with the increasing biomass share. Levelized electricity cost ranged between 55 and 75 $/MWh, which was by 5 to 25 $/MWh more than the reference electricity cost in 2014. Parallel to this, avoided CO2 emission cost was calculated, amounting to 70 to 370 $/t CO2 and decreasing with the increasing biomass share, which is substantially lower for the NGCC based scenarios compared to coal boiler-based ones.

López et al. (2018) [63] performed a techno-economic analysis of variable biomass share and plant electric output oxycombustion supercritical power plant and evaluated cost of energy, cost of avoided CO2 emissions, and net present value (NPV) for individual scenarios. The obtained results indicate that plant size affects the values of these performance parameters more than the biomass share, and an economically acceptable solution can be found in combination of plant size increase and biomass co-combustion.

Miedema et al. (2017) [56] compared various biomass supply chains with the coal one in Dutch conditions considering energy efficiency, renewable energy production, and GHG emissions. Each operation (mining/harvesting, transport, pretreatment) in the supply chain was attributed an interval of energy consumption and CO2 release. Torrefaction, chipping, pelletization, and combination of pelletization and torrefaction were considered as biomass pretreatment options. Calculations yielded that for 60% biomass energy share, total energy consumption increases by up to 30%, and GHG emissions decrease by up to 50%. The combined torrefaction and pelletization scenario exhibited best results. The authors concluded that the increase of total energy consumption with the increasing biomass share indicates that biomass introduction in power generation does not necessarily lead to a more efficient system, and under certain circumstances the GHG emission decrease can be even negligible.

Various other studies dealt with multifaceted aspects of biomass or waste co-combustion in terms of environmental, economic, or energetic performance within national or regional frames. An overview of these is provided in Table 1.

Relevant literature overviewed in Table 1 documents the actual trend of analyzing and modeling co-combustion utilization potential by various techniques and assessing its related secondary spatio-temporal aspects on the industry, environment, and society.

3. Biomass and Fossil Fuel Properties

Fuel composition resulting from its proximate and ultimate analysis as well as lower heating value counts among the main fuel quality parameters [8]. Table 2 presents characterization of a sample of biomass sources potentially available for co-firing, whereas Table 3 gives an overview of some solid fossil fuels characteristics. Biomass and waste generally contain more volatile matter and less fixed carbon and ash than coal, which in turn impacts their combustion characteristics.

As it results from Table 2 and Table 3, biomass, waste materials, and other solid materials that can be considered for co-combustion usually have much lower share of fixed carbon and much higher share of volatiles that common coals. Combustion of such solids proceeds faster, posing a problem in grate combustors if fuel is not well premixed, especially with bulk solid fuels like chips or package material. After a quick burnout of such unevenly distributed materials, locations with little or no fuel can form on the grate, which can subsequently lead to uneven combustion air distribution and, eventually, to grate damage. Fuel pretreatment via pelletization or torrefaction can increase the density and improve the burnout characteristics of bulk fuels, but it requires additional investment and operation costs [10].

Moisture content is an additional factor influencing fuel burnout. Elevated moisture content can be found in waste fuels such as woody residues or generally in fuels stored in open spaces. Apart from directly impacting the boiler and plant efficiency, it can contribute to higher greenhouse gases emissions due to its worsened burnout. Fuel pretreatment is dealt with in Section 4.

Table 4 provides an overview of basic ash chemical composition of selected materials. The presence and the ratio of basic (Fe, Ca, Mg, Na, K, P) and acidic (Si, Al, Ti) oxides content in ash determine its fusion properties and thus, in turn, its fouling and slagging tendency. Pronobis (2006) [37] defined the base to acid ratio as a measure of such ash behavior, alternatively termed slagging index [86]. Lawrence et al. (2008) [87] defined the fouling index as a novel tool for slagging propensity quantification. The higher the values of both indices, the higher is the slagging and fouling tendency of the given ash. Biomass ash generally exhibits stronger slagging and fouling tendencies than coal ash, which is corroborated by the values of both indices listed in Table 4. Most commonly used indices for slagging and fouling propensity expression are summed up in Sajdak et al. (2019) [88].

Combining the information from Table 2, Table 3 and Table 4, it can be concluded that ash content of woody biomass is usually lower than that of coals, whereas that of herbaceous biomass, bark, and various solid wastes is comparable with that of most coals. However, slagging and fouling tendency of individual materials is influenced by a higher extent by the base elements in ash than by ash content in the material solely. High ash fuels with high base in ash content can be considered as the most problematic ones. Higher content of SiO2 and Al2O3 in common coal ash compared to biomass ashes may be beneficial, as it forms aluminosilicates with base elements trapping them effectively in ash in co-combustion applications [11,13].

4. Biomass Pretreatment Biomass and waste exhibit several properties which impact their direct co-combustion feasibility:

- Low bulk energy density

- Higher moisture content

- Higher content of volatiles

Low energy density can be solved by decreasing the moisture content by pre-drying, pelletization, or their combination. Removing excess moisture by low potential heat application is a widely used unit operation [93,94], often integrated in heat and power plants with exhaust flue gas or low-pressure steam used as a cheap heat source [52,95]. Biomass with lower moisture has higher calorific value, and it generally yields more stable flame and does not require a high-quality supplementary fuel (usually natural gas) for the combustion process stabilization in the combustion chamber [95]. Dried biomass or waste can further be processed by milling, pelletization, or torrefaction depending on the combustion equipment design [31]. Similarly, composite pellets can be produced to improve the combustion characteristics of various solid fuels, wastes, and their mixtures, even with liquid component addition [96]. While pre-drying or other feedstock pretreatment improves its heating value and combustion characteristics, it is not recommended under any circumstances. A techno-economic study must provide the necessary inputs for decision-making considering the benefits in form of expectable higher boiler thermal efficiency and improved fuel burnout along with extra capital and operational costs related to logistics, storage capacities, additional infrastructure, and heat/power input needed. The generally positive results from laboratory studies on feedstock pretreatment should therefore be evaluated conservatively before application in industrial-scale systems.

Heating of biomass and waste to higher temperatures than necessary for their drying results in the release of volatile compounds and a change in its macromolecular structure. Its pretreatment in the temperature range of 200 to 300 °C with exposure times of up to 2 h in inert atmosphere is termed torrefaction [97,98], and it reduces the H/C and O/C ratio of the processed material and, thus, shifts its combustion characteristics closer to that of solid fossil fuels. The calorific value, structure, and bulk density of pretreated feedstock are also affected [99]. Loss of volatiles by torrefaction must, however, be accounted for in the material, energy, and economic balance of its pretreatment, together with heat needed for feedstock drying and torrefaction [100,101].

Xu et al. (2018) [92] studied physical properties of various waste material blends after their torrefaction in a convective furnace at 300 °C and exposure time of 3 to 120 min. They concluded that, depending on the material type, its heating value remained the same or increased, and the material loss was up to 55%. Tumuluru (2015) [102] assessed the changes in composition and energy properties of switchgrass and corn stover samples during torrefaction with varying temperature (180 to 270 °C) and residence time (15 to 120 min) in a thermogravimetric analyzer. The obtained results indicated a marginal improvement in higher heating value (HHV) of the studied samples and a significant (up to 58%) mass loss both due to moisture content reduction and extensive devolatilization at higher temperatures and longer exposures. The H/C ratio decreased from initial values of over 1.4 to around 0.6 under the most severe torrefaction conditions, while the observed trend for the O/C ratio was similar (decrease from 1.3 to 0.7). Similar results were achieved by torrefaction of other feedstock, including herbaceous, agricultural [99], and woody wastes [100].

Biomass based feedstock leaching has recently been intensely studied as a means of mineralogical composition adjustment to decrease its slagging and fouling propensity. Full scale results are still scarce. A comprehensive summary on this technique was provided by Madanayake et al. (2017) [103].

Table 5 sums up basic characteristics of the main body of analyzed papers. No biomass or waste pretreatment technique was used in the majority of studies, while drying and torrefaction are quite common techniques employed in laboratory scale studies. Various materials and their blends were studied nearly as often as single biomass or waste co-combustion studies. The studies are further classified and evaluated in Tables 6–10 showing individual system performance, plant layout, and operational issues aspects. See Table 6 below.

5. Direct, Parallel, and Indirect (Gasification) Co-Combustion

Available technologies offer several routes for biomass or waste and fossil fuel co-utilization for heat and power production, while the application of each depends on many technical, economic, and environmental aspects [32,36]. They are altogether referred to as co-combustion [10,36,74]:

- Direct co-combustion

- Parallel co-combustion

- Indirect co-combustion

Direct co-combustion is the most frequently applied option employing a single combustor with either common or separate feeds of fossil fuel and biomass or waste [89]. Both flue gas and solid residues are obtained as single material streams. Such solution requires the lowest specific investment cost compared to other co-combustion layouts [16,55]. Special applications of co-combustion, such as reburning or afterburning, are discussed in Section 8.

Parallel co-combustion employs separate combustors and the following heat transfer equipment for fossil fuel and biomass or waste [10]. Such a layout can be recommended for feedstock with low slagging and fouling propensity [103]. Separate ash streams are obtained, which may be an advantage if their properties differ substantially or the changeable biomass or waste composition poses a problem in direct co-firing. Table 7 documents the composition variability of fuel gas obtained from laboratory to full scale gasification and pyrolysis reactors operating with various feedstock and under various conditions.

Indirect co-combustion is realized by biomass or waste thermal treatment to obtain combustible gas (gasification) [166] or combustible gas, liquid, and solid fractions (pyrolysis) [167,168]. Such feedstock treatment requires higher specific investment cost compared to direct co-combustion [169,170] but allows diverting (a part of) the obtained material for other use than heat and power production: chemicals and fuels production [166], or highly efficient heat and power production in combined cycles [171]; both requiring extensive gas cleaning [172]. The obtained combustible gas can be introduced to fossil fuels combustors as reburning fuel [110], which contributes to nitrogen oxides emissions reduction [104,119,173].

6. Basic Types of Combustors and Biomass Share Biomass and waste co-combustion with fossil fuels proceeds in combustors adapted from sole fossil fuel combustion to co-combustion. Stationary and moving grate combustors as well as fluidized bed boilers are applied for this purpose, each of them being suitable for biomass or waste with specific physical and chemical properties. Besides large and pilot scale combustors, laboratory scale equipment is widely used nowadays, often coupled with multi-instrumental data analysis to assess combustion behavior phenomena and their interaction in the co-combustion mode.

A review by Dai et al. (2008) [13] summed up basic features of the most often used combustors. Grate furnaces are characterized by their low specific investment cost, low operational costs, and a wide range of biomass types regarding their moisture, sulfur, or ash content to be co-combusted. However, their operation is constrained to low combustion temperatures due to corrosion risk due to ash melting at higher temperatures. Fuels with fine particles are unsuitable for such combustor type. Fluidized bed combustors can accommodate a wide variety of fuels, but the associated investment costs made it interesting for large scale systems only (above 40 MWt). They are inflexible regarding the fuel particle size and suffer from corrosion when firing high alkali fuels. Increased carbon content in ash was also observed. Pulverized fuel combustors are usually effective only for low moisture fuels, but low NOx emissions can be achieved with appropriate burners and high thermal efficiency due to low oxygen excess required.

Al-Mansour and Zuwala (2010) [32] stated that over 150 large scale co-combustion applications existed worldwide in 2007, and more than 220 in 2009, with more than 100 of them being in Europe. They analyzed experience from various co-combustion options: direct, indirect (gasification), and parallel co-combustion, the latter two being far less commercialized. The underlying technologies were evaluated via technical indices including CO2 emissions, applicability, operational experience, efficiency, process economics, and optimal biomass share, with grate co-combustion technology with the lowest potential and indirect co-combustion as the most promising technology, followed by direct co-combustion in FB boilers.

Agbor et al. (2014) [31] summed up various co-combustion techniques and concluded that CFB boilers are the most suitable for this purpose, followed by cyclone combustion that, however, accommodates lower biomass shares. Pulverized combustion on the other hand, can decrease NOx emissions significantly. Direct co-combustion in packed bed systems is problematic due to thermal efficiency loss and ash sintering tendency. Certain technical difficulties can be overcome with biomass pretreatment, such as pelletization and torrefaction, increasing biomass energy density increased and its macromolecular structure changed, or by application of a separate biomass feeding system accompanied with optimized combustion air staging.

Hein and Bemtgen (1998) [17] summarized the experience accumulated during two years from laboratory, pilot, and full scale co-combustion investigations from several European Union (EU) countries participating in a dedicated EU project. Several biomass sources were analyzed including dedicated woody crops, agricultural residues, and other biomass wastes co-combusted in a pulverized fuel (PF) and fluidized bed (FB) mode with biomass share of up to 40% wt. Evaluated results included trends in greenhouse gases (GHG) emissions and corrosion rates for different biomass shares in combusted fuel. The authors concluded that a positive effect both in nitrogen oxides (NOx) and sulfur oxides (SOx) emissions can be seen with NOx emissions decrease of up to 40% in full co-firing mode, which is strongly affected by air staging and the lack of major decrease in fuel conversion. Slagging and fouling tendencies needed to be investigated in long term experiments, especially with high chlorine and high alkaline biomass co-combustion.

Tillman (2000) [19] analyzed the outcomes of a United States of America (USA) wide program dedicated to coal and biomass co-combustion commercialization and compared them with results of similar programs in the EU. Biomass shares of up to 50% wt. were reported from full scale facilities in the USA. Experience from these facilities confirmed the conclusions of Hein and Bemtgen (1998) [17] in terms of NOx emissions reduction exhibiting positive synergistic effect and a manageable decrease in boiler thermal efficiency of up to 2% in the co-combustion mode. The reported NOx trend was further corroborated in a publication by Tillman (2015) [34] stating that the observed NOx emission reduction was higher than what resulted from simple linear dependence assumption with varying biomass share in 65% of examined full scale systems. Moreover, a decrease of CO2 emissions of 2.7 to 3.15 ton per ton of combusted biomass was reported. Similarly to Tillman (2000) [19], Hughes (2000) [64] evaluated the underlying data from the USA facilities operating in the co-combustion mode and identified economics as the up-to-date major obstacle in further increase of biomass to power share.

Plant size (thermal input or electric power output) is a key factor determining the applied combustor type. Large plants (usually above 100 MWt) typically apply fluid combustors that offer excellent results both in terms of fuel burnout and produced greenhouse gases emissions [13,32,36]. Fuel particle size has to maintain within the desired interval, though. Such applications are best suitable for power production and cogeneration in thermal power plants as well as in large industrial and municipal heat and power plants and allow for biomass co-combustion ratio of above 20% wt. [13]. Pulverized fuel combustors are frequently applied in large scale applications where co-combustion proceeds either via a common system or in a separate fuel feeding system [19,31,89]. The first one requires adjustment of the existing fuel milling and delivery system and is typically suitable for biomass co-combustion ratio up to 5% wt. For the latter one, a complete independent biomass preparation and feeding system has to be constructed; however, the biomass co-combustion ratio can reach up to 20% wt. [31,34].

For plant sizes of several MWt to several tens of MWt, travelling grate furnaces and combustors are typical. They offer lower specific investment cost and lower operational costs in this size range than fluid combustors. They can fire a wide range of biomass types regarding their moisture, sulfur, or ash content. However, their operation is constrained to low combustion temperatures due to corrosion risk caused by ash melting at higher temperatures; they usually offer lower boiler thermal efficiency compared to fluid boilers or pulverized fuel boilers [31]. Fuels with fine particles are unsuitable for such combustor types. Grate combustors are often found in mid-size municipal heating plants. The majority of them have been refitted to co-combustion, sole biomass combustion, or to gas boilers.

Sub-MWt and domestic boilers traditionally employ fixed bed combustion, which offers poorer performance in terms of fuel burnout and greenhouse gases emissions compared to fluid or traveling grate combustors, especially when firing low calorific value fuels. As an inefficient and environmentally unfriendly technology, it has been ruled out and replaced by internal gasification boilers.

Hot water boilers and utility steam boilers refitted for co-combustion generally show lower risk of high temperature corrosion than power plant steam boilers due to lower temperatures of the hottest heat exchange surfaces. Steam superheaters and reheaters in power plant boilers are the most critical elements with surface temperatures of around or above 500 °C, which suits the deposition of alkali slags [8,10,89]. As the downgrade of steam parameters affects the power production efficiency, co-combustion of high chlorine and high alkaline biomass should be avoided in such installations, and the fuel slagging tendency should be managed with additives, as described in Section 7 in more detail.

Fuel premixing is another crucial factor affecting the combustor operation and efficiency in the co-combustion regime, especially in grate boilers and combustors. Lower density, larger share of volatiles, and faster biomass burnout in comparison with coal can lead to uneven fuel mix distribution over the grate and, subsequently, to formation of holes in the fuel layer after local biomass burnout. As a result, uneven air distribution can occur, followed by increased emissions and worsened fuel burnout on the rest of the grate.

Table 8 characterizes relevant papers from the biomass share and system performance point of view. The data overview corroborates the earlier findings by Tillman, Hughes, Hein, and Bemtgen that large scale systems employ biomass share usually less than 20% wt., whereas up to 100% biomass share applications were subject to computer simulations. Most studies used either boiler efficiency or specific fuel consumption as a straightforward energy performance indicator, while fewer of them analyzed the whole plant efficiency. Boiler efficiency (heat flux transferred to steam or hot water divided by total fuel energy input) reflects only energy losses associated with boiler operation change in the co-combustion regime, like fuel burnout, sootblowing steam consumption, and stack losses. It can be accepted as an objective criterion if produced steam parameters do not change in the co-combustion mode, or if the change in specific fuel consumption or that in internal power consumption is negligible. Plant efficiency (net plant power output divided by total fuel energy input) is influenced by more aspects than the boiler efficiency. Even if steam parameters in the co-combustion regime remain unchanged, the plant’s internal steam or power consumption may differ from those in the original fossil fuel operation due to necessary adjustments in storage, transportation, and feedstock pretreatment. A downgrade in produced steam parameters results in lower plant efficiency due to lower steam specific work in the turbine, and it might even limit the maximal plant output. Thus, it can be concluded that while boiler efficiency can provide certain information about the system performance in the co-combustion regime, plant efficiency should be always evaluated and should always be preferred as an objective performance indicator.

7. Slagging, Fouling, Corrosion, and Ash Properties

High content of alkali and alkaline earth metals in biomass is a commonly acknowledged reason for higher fouling and slagging propensity of biomass and biomass-derived fuels compared to coal; this effect is accompanied with often reported corrosion in biomass and fossil fuel–biomass combustors [8,35]. Fly ash particles stick to boiler surface more eagerly if a liquid film is formed, which contributes to fouling. Simultaneously, increased chlorine and sulfur content in some biomass-derived fuels and wastes enhances the low-temperature corrosion risk [36], while increased alkali content in fuels enhances slagging and high-temperature corrosion propensity. Alkali, alkaline earth metals, and sulfur entrainment in flue gas can lead to SCR catalyst deactivation. These factors negatively affect the plant efficiency and increase unplanned shutdown risk, but they also alter management costs. Table 9 documents numerous studies dealing with these aspects.

Stam and Brem (2019) [145] have recently analyzed the problem of boiler surface fouling during co-combustion of coal, wood, meat bone meal, and sheanut peels mixtures from the thermodynamic point of view to predict the Na-K-SO4-Cl salts eutectics occurrence and to assess the distribution of alkali metals in combustion products. Results indicated that suitable additives (e.g., ammonium sulfate) in suitable amounts significantly affect the presence of molten salts and therefore should be further examined with the prospect of boiler fouling suppression. A similar combined experimental and modeling approach was chosen by Sefidari et al. (2020) [21] for co-combustion impact assessment in an experimental iron ore pelletizing furnace, revealing that the complex co-combustion ash–iron ore dust system slagging tendency response to biomass share change varied significantly depending on actual operation conditions.

Zhang and Zhou (2019) [144] studied the effect of surface type on slagging characteristics during coal–corn co-combustion. They found that a nickel coated probe surface, compared with bare steel probe surface, exhibited weaker adhesion interactions with the slag formed, which resulted in repeated spontaneous slag shedding. Moreover, it slowed down the initial slag layer formation; both effects contribute to the increase of time-averaged heat flux through the nickel coated probe.

Opydo et al. (2019) [39] studied solids accumulation on various steel surfaces in a 400 MW circulating fluidized bed boiler in the coal–biomass co-combustion mode and analyzed the accumulates. Three types of steel commonly used in boilers were tested with their samples placed inside the boiler directly after final steam superheater for 12 h, where flue gas temperature reached around 850 °C. The front end section deposits were dense, sticking to the surfaces, and contained elevated amounts of sulfur and calcium as a result of calcium carbonate desulfurization method applied in the boiler. Alkali metals as well as aluminum and silica were found to accumulate preferentially in the rear section of the steel samples, with the rear deposits being less dense and consisting of fine ash and dust particles. No significant appearance or chemical composition differences were seen in the individual steel sample deposits.

Corrosive behavior of high alkaline biomass co-combustion flue gas was studied by Stephan et al. (2017) [128]. Straw and various coals were tested in a laboratory rig. High chromium content steel samples were placed in the combustor section for 24 h, where the flue gases reached 700 to 900 °C. Corrosion signal strength correlated with the straw share and chlorine content in the fuel, thus confirming earlier findings of Hein and Bemtgen (1998) [17]. On the contrary, Savolainen (2003) [106] did not detect any visible corrosion velocity increase in the full scale tests performed in a power plant boiler in the coal–sawdust co-combustion mode, most probably due to moderate biomass share in the fuel and much lower sawdust ash content compared to coals. Sondreal et al. (2001) [15] performed tests with various steel types to be used in future supercritical boilers under high sulfur–high ash content coal and high alkali biomass co-combustion conditions, finding that nickel–chromium alloys withstand the corrosive environment for 1000 h. Least affected was the alloy with highest chromium content, whereas those with chromium content below 20% wt. were affected to a much greater extent. Low temperature sulfur- and chlorine-based corrosion risk in co-combustion systems was investigated by Vainio et al. (2016) [174]. The system studied was a full scale bubbling fluidized bed boiler combusting bark, sludge, and solid recovered fuel. The results showed that sulfuric acid in flue gas in the vicinity of bag filters is minimal, which indicates efficient sulfur capture in ash; however, wet deposits rich in calcium and chlorine were observed on corrosion probes during long-term tests, which caused higher corrosion rates.

Physicochemical properties and chemical composition of ash obtained by co-combustion are directly related to co-combusted fuels, but are not additive measures [51]. Co-combustion ash can be characterized by bulk density, grains shape, loss on ignition, and melting temperature as the basic physicochemical indicators, and by chemical composition and metal content. Ash exhibits a very wide range of chemical composition due to varying biomass origin, as it is documented in Table 4 and data by Vassilev et al. [175,176] with the range of SiO2 content in biomass ash from <5 to >80% wt. and that of CaO from <2 to >60% wt. Such composition variability affects all biomass ash and co-combustion ash properties, especially with higher biomass share in co-combustion processes.

Bulk density of co-combustion ashes was found to increase with the increasing biomass content, by a factor of up to four [51]. Ash grains shape depends mostly on the ignition conditions and the combustor type. Wang et al. (2008) [177] indicated that co-combustion ash grains are significantly smaller than those produced by biomass combustion only. Priyanto et al. (2016) [38] made the same conclusion when examining properties of ash produced by co-combustion of coal and various woody biomass in variable ratios.

Biomass and coal ash melting point was investigated by Vassilev et al. (2014) [178]. Especially herbaceous biomass ash and marine algae ash, rich in alkali metal oxides, exhibit significantly lower melting temperatures than coal ash, with minimal initial deformation temperature below 800 °C compared to over 1100 °C for all investigated coals. On the contrary, husks, pits, and woody biomass in general have comparable or even higher melting temperature than average coals due to increased content of high-melting constituents. Namkung et al. (2018) [50] studied the fusion behavior of ash of woody biomass and low rank coal and their blends. After being heated at 1000 °C for three hours, particles’ structure and crystallinity of ashes were investigated by X-ray diffraction. The results corroborated the findings of Wang et al. [177], who observed ash particle size increase with the increasing biomass content in the blended fuel and confirmed the impact of phosphorus in blended ashes on their fusion behavior. Both Demirbas (2003) [89] and Dai et al. (2008) [13] concluded that the strength of biomass ash deposits is higher than that of coal combustion deposits only, and thus they are more difficult to remove. Priyanto et al. (2016) [38] recommended low ash content biomass to be co-combusted, preferably to reduce the ash fouling tendency. Hein and Bemtgen (1998) [17] summed up results from several full scale co-combustion trials, stating that at low biomass share, properties of the ash and fly ash formed resemble those from sole fossil fuel combustion, and though the slagging, fouling, and corrosion tendencies increased, they are at a tolerable level. More recently, results of low quality high ash lignite and herbaceous biomass co-combustion in a 500 kW combustor were presented by Fuller et al. (2018) [28], confirming only minor changes in the fly ash composition even at 50% co-combustion biomass share. Kopzyński et al. (2017) [127] found that ash from torrefied biomass samples co-combusted with coal exhibits higher initial softening temperatures than that from raw biomass co-combustion.

Addition of cheap and widely available additives to modify ash properties is a research subject of numerous current studies. Considered additives are coal ash, kaolinite, or S-based additives [35,139,145]. Their addition aims at devolatilization of alkalis and supporting their chemical interactions with aluminosilicates. Protective coatings of hottest boiler heat exchanger surfaces are also applied [53]. Yao et al. (2019) [90] tested the effect of K2CO3 addition to biomass–coal blends on the ash fusion and agglomeration properties and mineralogy, finding that it enhanced ash agglomeration and modified its fusion temperatures. All these findings were corroborated by further research by Yao et al. (2020) [40] focused on coal–pine sawdust ashes properties and their modification by K2CO3 addition, an effective trap for volatile alkalis in the formed glassy phase. Stam and Brem (2019) [145] examined ammonia sulfate addition effect on possible Na-K-SO4-Cl eutectics formation. While the use of sulfur-containing additives seems to be contradicting the effort to suppress boiler corrosion, it has a beneficial effect on alkali and chlorine entrapment in ash, reducing thus the high temperature corrosion risk [10].

Jeong et al. (2019) [147] determined an optimal co-combustion ratio for coal with wood pellets and empty fruit bunches as 10 and 15% wt., respectively. Increasing the biomass co-combustion share up to these thresholds resulted in lower ash deposition due to overall ash amount decrease. Above the threshold values, however, biomass-origin ash agglomeration led to increased ash deposition. Kazagic et al. (2018) [23] investigated fouling and slagging properties of ash from different biomass and coal co-combustion ratio using Bosnian coals and woody biomass or miscanthus obtained in a laboratory temperature-controlled furnace. The results showed that while unburned carbon content in ash deposits was negligible in all fuel composition combinations, in slag collected at the bottom of the furnace the carbon content increased from <1% wt., with biomass fraction in fuel increase from 15% to 25%. Ash slagging and fouling tendencies remained low to medium in all investigated cases at the combustion temperature of 1250 °C but increased significantly in experiments with combustion temperature of 1450 °C. Ash softening temperature was estimated in the range of 1200 to 1300 °C for all ash samples.

Pedersen et al. (1996) [18] reported on full scale straw–coal co-combustion in a pulverized coal boiler. No discernible trend in the carbon content in ash was observed for the 10 and 20% biomass share trials, respectively, compared to coal combustion only. A similar conclusion was reached by Savolainen (2003) [106] on evaluating pulverized coal and sawdust co-combustion in a large power plant boiler with up to 25% wt. of biomass share in blended fuel. In addition to comparable results obtained, Skodras et al. (2002) [44] concluded that more unburned carbon was found in fly ash (up to 6% wt.) than in bottom ash (typically around 2% wt.). Steer et al. (2013) [120] analyzed full scale miscanthus co-combustion in coal power plant boilers, concluding that carbon burnout was seriously affected by biomass particle size fed to the boilers and, to some extent, also by secondary air amount and distribution. Increased slagging tendency was observed with the increasing miscanthus share in the combusted fuel. Kalembkiewicz and Chmielarz (2012) [51] reviewed several papers dealing with carbon burnout with various fuel blends combusted, finding examples of both increased and decreased carbon content in ash reported in co-combustion tests and identified particle size, fuel moisture, and burner type as the most important factors determining the final carbon content in ash.

Fly ash from co-combustion can be utilized in concrete production as proposed by Baxter (2005) [35] and Leckner (2007) [36] due to its confirmed high pozzolanic activity [51]. Co-combustion fly ash from full scale applications in Netherlands utilizing various biomass and waste types were examined by Sarabèr (2014) [179] as possible mortar or concrete additives, confirming their general suitability for these purposes despite their variable chemical composition and the earlier evidence summed up by Sondreal et al. (2001) [15].

Table 9 indicates the research scope of relevant literal sources in operational and process aspects.

8. Combustion Process Modifications: Air Staging, Oxycombustion, Flue Gas Recirculation, and Reburning

Along with the sole biomass co-combustion fraction effect on combustion characteristics and combustor operational issues, several other process modifications were tested in parallel [119,129], including both measures commonly applied in fossil fuel power plant boilers to decrease NOx emissions (air staging, flue gas recirculation, fuel reburning) [133,151,180] as well as oxycombustion, which should improve boiler thermal efficiency and allow for effective carbon capture from flue gas [42,123]. These can be successfully applied both in heat and power production as well as in heavy industry (steel, clinker, or aluminum production).

Oxycombustion can be applied in most industrial boilers and furnaces [181] but its potential for fuel saving is especially high in the aluminum production industry, where it has been estimated to be as high as 50% [182,183]. In addition, it can contribute to charge melting time shortening, as presented by Dzurňák et al. (2019) [184] and thus improve the melting process productivity and its environmental impact [185]. In combination with other measures including improved heat recovery [186] and the use of biofuels and power from biomass [187], substantial reduction in GHG emissions from aluminum production can be achieved.

The performed studies concluded that NOx emission reduction by air staging, flue gas recirculation, and fuel reburning can further be enhanced by biomass co-combustion, as the volatiles released in early stages of biomass combustion serve as an effective agent for nitrous oxides reduction. However, certain problems with carbon burnout were reported, and a compromise between NOx emissions reduction and thermal efficiency loss has to be sought. Oxycombustion can alleviate this negative effect, and it is often applied in combination with some of the above measures [123,142,153]. Table 9 provides an overview of these measures applied either individually or in parallel.

9. Emissions of Greenhouse Gases and Other Pollutants

Carbon dioxide emissions in the co-combustion mode are described in Section 2. Here, other gaseous emissions, namely NOx, SOx, CO, and others, are considered.

Tchapda and Pisupati (2014) [11] analyzed the co-combustion technology in a voluminous review paper, identifying both fuel and air nitrogen as significant contributors to nitrogen oxides emissions, regardless of whether fossil fuel or biomass is combusted. Thus, lower nitrogen content in biomass compared to coal generally led to a decrease in NOx emissions [49]; however, this issue is more complex, and cases with increased NOx emissions during co-combustion have also been reported [35]. This is corroborated by the results of experimental combustor of woody biomass-coal co-combustion trials performed by Yelverton et al. (2020) [155] that yielded higher, equal, or lower NOx emissions in 20 as well as in 40% biomass mass share trials with no discernible trend. Both Sondreal et al. (2001) and Baxter (2005) [15,35] argued that biomass often contains more moisture than coal, which leads to combustion temperature decrease and reduced NOx emissions. This was confirmed in industrial scale experiments described by Wieck-Hanssen et al. (2000) [105], when coal and straw co-combustion yielded almost the same NOx emissions as the combustion of coal only. As pointed out by Karampinis et al. (2014) [10], attention has to be paid to suitable air distribution to allow for efficient combustion of volatiles released from biomass as well as to air staging further reducing the NOx emissions. Other means of nitrogen oxides reduction comprise reburning and flue gas recirculation as discussed in the previous chapter.

Co-combustion has been proven to reduce sulfur oxides emissions due to effective sulfur recapture by calcium if present in the co-combusted biomass or waste ash in higher content than in fossil fuel ash and especially in fluid boilers, enabling far better contact of flue gas with ash than grate boilers [10,31]. This biomass effect can be combined with limestone addition to decrease the sulfur oxides emissions even further, as documented by Atimtay et al. (2017) [85]. Increasing combustion temperature reduces the sulfur capture efficiency. Chen et al. (2018) [134] conducted thermogravimetric measurements of sewage sludge, coal, shiitake substrate, and their blends combustion to assess the synergistic effect of biomass addition on the energetic and environmental combustion indicators. Sludge–coal co-combustion proved the most effective in CH4, NOx, and SO2 emissions reduction, whereas sludge–shiitake co-combustion led to an increase in CH4 and NOx emissions at the sludge share of 25% with their gradual decrease on further sludge share increase. Skodras et al. (2002) [44] confirmed the sulfur oxides emissions reduction in wood–lignite co-combustion experiments in an industrial boiler, and similar conclusions were drawn by Steer et al. (2013) [120] after miscanthus-coal co-combustion tests in a 500 MWt power plant boiler.

No clear trend can generally be drawn in CO emissions, being often more dependent on air excess and distribution than on the co-combustion ratio, as stated by Skodras et al. (2002) and Lukáč et al. (2019) [44,188]. Sami et al. (2001) [8], on the other hand, summed up the results of several industrial co-combustion trials and concluded lower CO emissions of most of them than in sole fossil fuel combustion, along with SOx and NOx emission decrease. Biomass pre-drying has a certain positive role in CO emissions reduction, as argued by Verma et al. (2017) [52]. Steer et al. (2013) [120] observed an increase in CO emission in the miscanthus–coal co-combustion compared to coal combustion only, which they attributed to insufficient air delivery for complete combustion of volatiles rapidly released from miscanthus. The same effect was confirmed for CO emissions increase in bagasse–coal co-combustion studied by Bragato et al. (2012) [113]. Recent woody biomass–coal co-combustion trials performed by Yelverton et al. (2020) [155] did not provide any clear dependence of CO emission on the biomass share or type.

Table 10 provides a structured view on the type of emissions investigated in multiple studies. While almost all papers analyzed the NOx and SOx emissions, fewer of them dealt with CO and yet fewer investigated other gaseous emissions such as VOC (volatile organic compounds), dioxins, metals, or chlorine emissions.

Finney et al. (2018) [45] investigated metal aerosol emissions during biomass and coal combustion in a pilot scale combustor. Coal contained more than 3% wt. of ash on dry basis, whereas that in the woody biomass was below 0.8% wt. Potassium emissions from woody biomass combustion were more than six times higher, but emissions of other alkali and alkali earth metals were significantly lower than those from coal combustion. Nickel, zinc, and chromium emissions were comparable in both cases following no clear dependency on their content in ash. Emissions of other metals were significantly lower in the case of biomass combustion, which confirmed the earlier findings of Hein and Bemtgen (1998) and Dai et al. (2008) [13,17]. Guo and Zhong (2018) [138] performed combustion experiments with coal and composite biomass pellets in a fluidized bed combustor. They observed a synergic effect of both fuels co-combustion, leading to lower polyaromatic hydrocarbons emissions than expected in a broad range of combustion temperatures. The same result was obtained for trace metals emissions expressed in terms of volatilization rate reduction, which the authors attributed to chemical interactions of alkalis in biomass ash capturing other metals. Their findings related to polyaromatic hydrocarbons emissions corroborated the earlier conclusions of Bragato et al. (2012) [113] obtained in coal–bagasse co-combustion tests in a wide combustion temperatures interval. Skodras et al. (2002) [44] performed a study on coal and various woody fuels co-combustion in an industrial boiler dedicated to dioxins and metals emissions assessment. Dioxins emissions could neither be linked to carbon burnout in ash nor to co-combusted biomass type. Metals’ emissions were lower than expected based on pure coal or biomass combustion trials. More recent studies regarding the gaseous emissions from co-combustion processes were published by Fu et al. (2019) [46] and Xue et al. (2020) [29]. Xue et al. (2020) [29] found that co-combustion of coal and wheat straw in a fluidized bed combustor restrained zinc, cadmium, and lead from release in flue gas, while the release of chromium was promoted. They also observed a significant impact of secondary air introduction on the metals’ emissions, indicating no effect on chromium emissions but an increased effect of zinc, cadmium, and lead. An increase of volatilization ratio for copper, chromium, and zinc was disclosed by Fu et al. (2019) [46] in coal–sewage sludge co-combustion experiments in a thermogravimetric analyzer, while that of arsenic decreased and that of nickel and lead remained unchanged. It can thus be concluded that while there is enough evidence of the decrease of polyaromatic and carcinogenic emissions release during co-combustion, the release of metals is a complex problem and needs to be studied further, both in co-combustion studies and in separate combustion of fossil and renewable fuels in industrial [189] as well as domestic boilers [190].

10. Challenges and Future Development The review of relevant literature highlighted the rapid technologic advances in biomass and waste co-combustion with fossil fuels. However, several weak points need to be further addressed and should be a part of future co-combustion technology and equipment development:

  • Deeper understanding of carbon and GHG emissions lifecycles in co-combustion applications is needed. While using local sources of waste biomass and other wastes has the potential to reduce the GHG emissions significantly, on-purpose growing, harvesting, transporting, and co-combusting biomass should be studied carefully. The resulting net GHG balance can be close to zero or even negative in some cases, as demonstrated by Miedema et al. (2017) [56].

  • There is no single recipe or standardized approach to specify optimal co-combustion share, plant size, and layout. Regional and local aspects must be always analyzed regarding the resources availability and variability, plant size and layout, biomass and waste pretreatment possibilities, the resulting GHG, and other emissions and ash utilization, as well as long term effect of fouling and possible corrosion—all this shapes the optimal design and operation of each particular co-combustion installation.
  • Biomass processing routes to fuels and chemicals play an important role in decision making on optimal biomass and waste utilization, as they advance towards their full commercialization, possibly restraining co-combustion application to low quality or contaminated or otherwise unfavorable fuels. The development of electro mobility on the other hand might enhance the co-combustion application in low carbon power production as a result of increased electricity consumption.
  • Advances in gasification and pyrolysis processes of mixed fossil and biomass/waste fuels are necessary to make those technologies fully available and competitive. Further process modifications, including new methods for biomass pretreatment, should be developed regarding NOx and other GHG emissions decrease and reduced risk of equipment corrosion.

11. Conclusions Co-combustion represents a viable and widely applied technology with the potential to reduce GHG emissions from heat and power generation in near and mid-term future, especially with local biomass and waste sources exploitation. Retrofit of existing fossil fuel boilers is associated with low specific cost and reasonable co-combustion levels of up to 20% wt. Most analyzed studies concluded that no significant tendencies in fouling and equipment corrosion were identified unless for co-combustion of combined high-ash and high-sulfur content biomass (herbaceous biomass). Rational application of air staging, flue gas recirculation, and fuel reburning in co-combustion applications can further enhance their positive synergic effect towards significant reduction of nitrogen oxides emissions without significant increase of carbon monoxide emissions and unburned carbon in ash. If combined with oxycombustion, an additional bonus in increased combustor thermal efficiency can be obtained. Feed type and moisture content, combustor type, and air distribution were identified as relevant factors affecting the GHG emissions, which pose a challenge for continuous development of cost-effective feed pretreatment methods and combustor design optimization. As proven by numerous studies, biomass ash is capable of sulfur capture, thus reducing sulfur oxides emissions. Emission trends of polyaromatics and other carcinogenic substances in the co-combustion regime deserve further research. The well documented volatilization and emissions of alkali and alkali earth metals during co-combustion is closely related to slagging and fouling. Possible synergies of volatilization ratios of other metals remain largely unclear and deserve a more systematic research. The obtained ash is effectively utilized in the civil engineering sector as demonstrated by several research studies as it meets the technical requirements for cement and mortar additives. Ash properties are significantly altered in the co-combustion regime if the ash content in the co-combusted fuel and its mass share in the fuel blend are sufficiently high. High calorific value biomass with low ash content should thus be co-combusted preferentially. As an established technology, co-combustion has to face the near future competition with alternative pathways of biomass and waste conversion to other products, fuels and chemicals, to contribute to long-term reduction of greenhouse gases emissions. On the other hand, the expected increase of power consumption as a result of electro mobility development is to its advantage. However, the expected gradual shutdown of coal power plants will limit the direct co-combustion potential in further decades.

Reference Studied Systems Approach Evaluated Aspects
Hein and Bemtgen (1998) [17]Various fuels, co-feeding ratios, boiler types, and thermal outputs from 0.3 to 150 MWtEU project; Experimental Fuel conversion, Chlorine and GHG emissions, content of heavy metals in ash
Hughes (2000) [64]Survey on realized co-combustion application in the USAOpinion on economic, environmental, and political aspects of co-combustion
Mann and Spath (2001) [65]Coal fired power plant 360 MWe in co-combustion modeSoftware analysis, LCAGaseous and other emissions, energy efficiency, biomass utilization sensitivity to GWP
Sami et al. (2001) [8]Detailed survey on realized and planned co-combustion application in the USA and in the EUReview paperTechnical aspect: fuel properties and preparation, boiler types, emissions, carbon burnout
Royo et al. (2012) [66]Case of Spain, co-combustion potential in existing coal fired power plantsAvailable biomass LCA assessmentNation-wide GHG emissions reduction and power from biomass production potential
Lüschen and Madlener (2013) [67]Case of Germany, co-combustion potential in new coal fired power plantsTechno-economic analysis by simulation. Marginal analysis. Statistical evaluation.NPV, its sensitivity in various scenarios.
Gu et al. (2013) [68]Industrial FB boiler in coal-biomass co-combustion modeSimulation software ECLIPSEPlant efficiency, CO2 savings, project NPV
Kazagic et al. (2016) [69]Coal power plant in SerbiaBiomass availability assessment, economic analysisEnvironmental and economic PI
Mohd Idris et al. (2018) [70]Power plant in Malaysia, coal + palm oil biomassBiomass supply chain assessment, techno-economic assessment and optimizationMulticriterial optimization of biomass utilization, environmental and economic PI
Nyashina and Strizhak (2018) [71]Potential of composite fossil—biomass fuel use in RussiaLaboratory rotary muffle furnace + gas analyzerEnvironmental PI
Pikoń et al. (2019) [72]Comparative analysis, waste fuel and lignite—case of PolandLaboratory TGA, LCA based on the results Environmental PI
Smolinski et al. (2019) [73]Fuel produced from sewage sludge treatment and coal—case of Poland Pilot plant for sewage sludge treatment; profitability analysisEconomic and environmental PI
Truong et al. (2019) [74]Assessment of straw and rice husk cofiring in VietnamSpatio-temporal analysis, techno-economic evaluation, sensitivity analysisGHG emissions reduction, fossil, and renewable electricity production costs
Glushkov et al. (2020) [48]Testing co-combustion of new composite fuels in a laboratory tube muffle furnace, results applied to three regions in Russia via fossil fuel saving calculations.TIC, financial savings

Reference [75] [75] [76] [76] [77] [78] [27] [79] [80]
Sample Straw Wood Eucalyptus Bark Rice Husk Woody Residues Laying Hens Manure RDF (Sample Plastics Blend) Automobile Shredder Residue Aseptic Milk Package (Tetrapak)
Proximate analysis, % wt.
Fixed carbon15.4417.0539.918.69.33.67 db6.07 db10.008.16
Volatile matter66.4074.1443.154.437.467.01 db82.67 db71.1076.92
Ash7.130.4110.718.20.429.32 db11.25 db18.005.96 + 6.1 Al foil
Moisture11.038.406.38.852.912.171.230.502.8
Ultimate analysis, % wt.
Carbon38.88 ar45.94 ar41.70 ar37.4752.4 db38.40 db58.09 db58.88 daf47.33 daf
Hydrogen5.44 ar5.50 ar4.60 ar4.645.9 db5.91 db9.38 db6.75 daf7.17 daf
Oxygen36.75 ar39.65 ar36.10 ar30.9040.6 db21.7420.39 db13.55 daf30.26 daf
Nitrogen0.70 ar0.08 ar0.54 ar0.590.19 db4.190.35 db1.42 daf0.26 daf
Sulfur0.01 ar0.02 ar0.06 ar-0.022 db0.44-0.90 daf0.06 daf
LHV, MJ/kg14.35 ar17.13 ar14.70 ar14.36 ar9.924 ar12.36 ad31.23 db--

Reference [81] [81] [15] [82] [83] [46] [84] [85]
Sample Highvale Coal Eastern Bituminous Illinois Bituminous Czech Coal “Sokolov” Yunnan Low Rank Coal Industrial Coal Slurry Taldinsky Hard Coal B-Goynuk Lignite
Proximate analysis, % wt.
Fixed carbon43.8955.5244.233.6431.91 db36.62 ad46.2823.65
Volatile matter37.1534.9137.437.1921.40 ab57.51 ad32.9239.63 db
Ash11.398.8214.722.4646.70 db34.92 ad8.6724.59 db
Moisture7.610.753.76.717.00.95 ad12.1333.91
Ultimate analysis, % wt.
Carbon60.70 db77.33 db80.2 daf50.20 daf40.44 db53.29 ad63.45 ar55.57 db
Hydrogen4.01 db5.08 db5.7 daf4.01 daf2.99 db3.89 ad4.79 ar10.29 db
Oxygen21.86 db6.29 db7.0 daf15.49 daf7.05 db9.41 ad8.85 ar4.93 db
Nitrogen0.84 db1.45 db1.7 daf0.73 daf0.78 db0.83 ad1.81 ar1.73 db
Sulfur0.28 db0.96 db5.4 daf0.58 daf2.05 db0.65 ad0.30 ar2.89 db
Higher heating value, MJ/kg21.59 ar32.13 ar27.31 ar19.56 (LHV, ar)14.46 ad22.07 ad25.02 (LHV, ar)20.62 db

Reference [18] [38] [89] [90] [91] [92] [15] [38] [89] [91]
Sample Compound % wt. Wheat Straw Sakura Wood Red Oak Wood Soybean Stalk Poultry Litter Blend of Fibrous and Plastic Waste US Wyoming Subbit. Coal Bituminous Coal Coal Turkish Lignite
SiO258.05.64933.184.73334864.24253.71
Al2O33.21.49.52.551.09271921.42024.08
Fe2O31.52.28.51.75-0.9124.4517-
CaO6.051.717.530.9539.5221161.025.52.48
MgO1.417.21.18.236.223.04.10.882.11.73
Na2O0.90.60.53.565.111.60.70.581.40.76
K2O14.04.49.515.7226.530.61.01.525.81.41
P2O52.82.91.82.43---0.19--
Slagging index [37]0.4311.290.661.7513.300.450.500.100.510.08
Fouling index [87]6.556.46.633.8420.71.00.90.23.70.2

Ref. 1 2 3 4 5 6 7 8
Fos. B + W Ene. Ec. Env.
[15]R2001MMD, Ot.FSYYYYY
[18]O1996SSNFS (PPB)NNYYY
[17]O1998MMVMYNYYY
[104]O2000MMD, Ot.L (F + REB)NNYYN
[19]O2000MMDFSYNYYY
[105]O2000MSNFS (PPB)NNYYY
[64]O2000MMNFSNYYY*N
[8]R2001MMVFSYNYYY
[65]O2001SMNFS (PPB), CYNYY*N
[44]O2002SMNFS (IB)NNYYY
[82]O2003SSNL (PFBA)NNYYY
[106]O2003MSNFS (PCB)NNYYY
[89]R2003MMNMNNYY*N
[107]O2005SSNP, C (PCB)NNYNN
[37]O2006SMNCYNYYY
[108]O2007SSNP, FS (CFBB)NNNYN
[36]R2007MMDFSYYYYY
[33]O2007MMNFSYNYYN
[13]R2008MMNFS, CYNYYY
[109]O2008MSNL (EFR)NNYYY
[32]R2010MMNM—FSNNYYY
[110]O2011SMNL, C (FBB + PY + REB)NNYYN
[111]O2011MSNL (F + REB)NNYYY
[51]R2012MMNM—FSNNYNY
[112]O2012SMGC (BG + REB)NNYYN
[113]O2012SSNL (BF)NNYY*N
[114]O2012MMNFS, CYNYYY
[115]O2012MMNP, CYNYYN
[116]O2012MSNL (EFR)NNYYY
[117]O2013MSNL (TGA, DTGA)NNNYN
[118]O2013MMOt.L (TGA, DTGA)NNNYN
[68]O2013SSNFS, CYYYY*N
[119]O2013SSGP (BG+REB)YNYYN
[57]O2013SSNFS, CYNNYY
[120]O2013MMDL, FS (PPB)NNYYY
[31]R2014MMT, G, Ot.M—FS (BG + REB)NNYYY
[121]O2014SMNL (DTF)NNYYY
[11]R2014MMT, G, Ot.M—LNNYNY
[10]R2014MMVFS (BG + PY)NNYYY
[86]O2015SMNL (IFR)NNYYY
[122]O2015MSNL (CFBC)NNNYY
[123]O2015SSNFS, C (PPB + CFD)NNNYY
[124]O2015SSNL, C (F + CFD)NNNYY
[41]O2015SMNL (CFBC)NNYYN
[125]O2016SSNL (F + REB)NNYYY
[25]O2016SMNL (TGA, DTGA)NNNYY
[38]O2016SMDL (DTF)NNNYY
[49]O2016MSNL (PFF)NNYYY
[69]O2016MMNFSYYYY*N
[55]O2016MMNFS, CYYYY*N
[126]O2016MSNL (EFR)NNYYY
[58]O2017MSNFS, C (CB + CFD)NNYNN
[127]O2017SMTL (FBC)NNYYY
[103]R2017MMVM—FS, L NNYYY
[78]O2017SSDL (TGA, DTGA)NNNYN
[85]O2017MSNPYNYYY
[84]O2017SSTPYNYYN
[128]O2017MSNL, P (PFC)NNNYY
[129]O2017SSDFS, CYNYYY
[56]O2017SSVFSYNYY*N
[52]R2017MMDM—FSNNYY*N
[42]O2018SSNL (CFBC)NNYYY
[20]O2018SSDFS, CYNYNY
[26]O2018SSD, TL (TGA, DTGA)NNNYY
[130]O2018SSNCYNYNN
[131]O2018SMTL (DTF)NNNNY
[132]O2018MMTLYNYYY
[91]O2018SMTL (SPR)NNYYY
[22]O2018SMDL (DTF + TGA)NNYYY
[133]O2018SMNP (F)NNYYY
[134]O2018SSNL (DTF + TGA)NNYNY
[71]O2018MMDLYYYYN
[45]O2018SSNP (PFC)NNYNY
[50]O2018SMDL (TGA, DTGA)NNNYY
[135]O2018SSNFS (IB—MG)NNYY*N
[63]O2018SSDFS, CYYNYN
[136]O2018MSNL (PFF)NNYYY
[23]O2018MMNL (DFT)NNYYY
[28]O2018MSNP (PFC)NNNYY
[137]O2018-MNM, CNNNYY
[138]O2018SSNL (FBC + TGA, DTGA)NNYYY
[70]O2018SMTFS, CYYYY*N
[139]O2019SSDL (DTF)NNNYY
[140]R2019MMNM, C (CLC)NNYYY
[47]O2019MMDL (TGA, DTGA)NNNYY
[141]O2019SSDL, C (TGA)NNNYY
[39]O2019MMNFS (CFBB)NNNYY
[142]R2019MMNM, CYYYYY
[143]O2019SMOt.L (TGA, DTGA)NNNYY
[43]O2019SSDL, P, C (DTF + CFBB)NNYYY
[83]O2019SSNL (TGA, DTGA)NNNYY
[144]O2019SSNP (F)NNNNY
[145]O2019SMNFS, C (ash samples)NNNYY
[90]O2019SSNL (MIA—ash samples)NNNYY
[46]O2019SSDL (TGA, DTGA)NNYYY
[146]O2019SSNM, C (CFD)NNYNY
[147]O2019SMDL (DTF)NNYYY
[148]O2019SSDL (TGA, DTGA)NNNNY
[88]O2019MMNL (MIA)NNNNY
[24]O2019MSNL (DTF + TGA)NNNYY
[149]O2020SSTP (PFF)NNYYY
[150]O2020SMDL (MIA)NNNYY
[29]O2020SSNL (FBC)NNYYY
[59]O2020SSNFS, C (FBC + CFD)NNYYY
[151]O2020SSNFS, C (UGB + REB)NNYYY
[152]O2020SMNL, C (CLC + CFD)NNYYY
[21]O2020SMN(pelletizing grate kiln) P, CNNNYY
[153]O2020SSNL, C (F + CFD)NNYYY
[40]O2020SSDL (MIA—ash samples)NNNYY
[154]O2020SSTL (TGA, DTGA)NNNNY
[27]O2020MMNL (TGA, DTGA)NNNYY
[155]O2020SMTP (PFC)NNYY*N
[48]O2020SMNL (TF)NNYYY
[156]O2020SMNL (TGA, DTGA)NNYY*Y
[157]O2020MMNL (TGA, DTGA, TF)NNYY*Y
[158]O2020SSNL (MIA)NNNY*Y

Ref. Fossil Fuel Biomass/Waste
Description 1 2 3 4 Description 1 2 3 4
[18]High sulfur bituminous coalMYYYWheat strawSh, PYYY
[104]Coal, natural gasMYYYHard- and softwoodSh, SYYY
[19]Coal, oilVYYYVarious biomass types + sourcesVYYY
[105]Two types of coalMYYYSurplus straw from farmingSh, MYYY
[8]CoalsVYYYMultiple biomass and waste typesVYYY
[65]Coal Illinois No. 6NNNNMultiple biomass typesNYYY
[44]Greek ligniteNYYYMultiple biomass and waste typesNYYY
[82]Czech Sokolov coalSYYYWood chipsSh, SYYY
[106]Polish and Russian coalMYYYPine sawdustNYYY
[89]Multiple coal typesNYYYMultiple biomass typesNYYY
[107]Bituminous UK coalMYYNPinewood pelletsM, SYYN
[37]Upper Silesian coalNYNYWood, straw, sewage sludgeNYNY
[108]CoalNYYNWood chipsNYYN
[36]Multiple coal typesNYYYMultiple biomass and waste typesNYYY
[33]Lignite and bituminous coalMYYNMultiple biomass typesMYYN
[13]Multiple coal typesMYYYMultiple biomass and waste typesMYYY
[109]Four coal typesM, SYYNEucalyptus biomassM, SYYN
[111]NG, coalNYYYPine sawdustNYYY
[112]Hard coalNYYNSewage sludge, two typesNYYN
[113]Coal Pittsburgh No. 8M, SYYYSugarcane bagasseM, SYYY
[114]Two coal typesNYYYFour biomass typesNYYY
[116]Two coal typesM, SYYYOlive wasteM, SYYY
[117]Two coal typesM, SYYYWood pelletsM, SYYY
[118]Turkish lignitesMYYYTwo waste biomass typesM, ShYYY
[68]CoalNYYYTobacco wasteNYYY
[119]Polish hard coalNYYYAlder wood chipsNYYY
[57]Coal Pittsburgh No. 8NYYYWoodNYYY
[120]Coal and coal ashM, SYNYSpruce + MiscanthusM, SYNY
[31]Multiple coal types, NGVYYYMultiple biomass typesVYYY
[121]CoalNYYYStraw, woodNYYY
[86]Hard coalMYYYStraw, woody biomassMYYY
[122]Two lignitesMYYYOlive cakeMYYY
[123]CoalMYYYBiomassMYYY
[124]CoalMYYYBiomassMYYY
[41]Bituminous coalNYYYThree biomass typesNYYY
[25]Bituminous coalMYYYCorncob and hardwoodMYYY
[38]Bituminous coalM, SYYYFour woody biomassesM, SYYY
[49]Two coals + LPGM, SYYYWoody biomassM, SYYY
[126]Coal blends, NGMYYYBiomassMYYY
[58]Two CoalsMYYYPine sawdustMYYY
[127]Hard coalNYYYVarious biomass typesNYYY
[78]Gas-flame coalMYYYLaying hens manureMYYY
[85]Two lignitesNYYYRed pine chipsNYYY
[84]Hard coalSYYYTorrefied biomassPYYY
[128]Three coalsMYYNStrawMYYN
[129]CoalNYYYSawdustNYYy
[56]CoalNNNYPoplar chipsNNNY
[42]LigniteNYYYWood pelletsNYYY
[20]LigniteMYYYBiomassMYYY
[26]Coal Illinois No. 6NYYYAvocado pitsM, SYYY
[130]Natural gasNYYYBiomassPYYY
[131]CoalM, SYYYVarious biomass typesM, SYYY
[132]Two coalsM, SYYYTwo biomass types, each raw or torrefiedM, SYYY
[91]LigniteM, PYYYTwo biomass types, each raw or torrefiedM, PYYY
[22]Black coalM, S, PYYYSewage sludge and Shiitake substrateM, S, PYYY
[133]Natural gas (methane)NNNNThree simulated syngasesNYYY
[134]AnthraciteM, SYYYRDFM, SYYY
[71]Coal water slurry, used turbine oilNYYYVarious forest biomass typesM, SYYY
[45]CoalMYYYWhite wood pelletsMYYY
[50]Indonesian low rank coalM, SYYYSewage sludge, woody biomassM, SYYY
[135]Czech brown coalNYYYSolid recovered fuelNYYY
[63]CoalMYYYBiomassMYYY
[136]Australian bit coal + LPGNYYYWoody biomassNYYY
[23]Low rank Bosnian coalsMYYYSawdust and MiscanthusMYYY
[28]Greek lignite and NGM, SYYYBiomassM, SYYY
[138]Bituminous coalNYYYComposite biomass pelletsPYYY
[70]CoalNNNNPalm oil production residual biomassPNNY
[139]CoalMYYNBiomassMYYN
[47]Three coalsM, SYYYTwo wastesM, SYYY
[141]LigniteSYYYPine sawdustSYYY
[39]Coal, coal slurryNYYYSunflower pellets and woodchipsNYYY
[143]Australian coalNYYNOat straw, gumwoodNYYN
[43]AnthraciteMYYYSawmill sludgeMYYY
[83]Low rank coalM, SYYYTobacco stalkM, SYYY
[144]CoalNYYYCorn stalkNYYY
[145]Coal blendsNYYYMultiple biomass typesNYYY
[90]Bituminous coalNYYYSoybean stalkNYYY
[46]Industrial coal slurryMYYYMunicipal sewage sludgeMYYY
[147]Bituminous coalM, SYYYEmpty palm fruit bunches, wood pelletsM, SYYY
[148]Bituminous coalM, SYYYMicroalgae biomassM, SYYY
[88]Two coalsM, SYYYSawmill wood waste, miscanthusM, SYYY
[24]Two coalsM, SYYYWood pelletsM, SYYY
[149]Hard coalMYYYPelletized sawdustP, MYYY
[150]anthraciteSYYNThree hydrocharsSYYN
[29]CoalNYYNWheat strawNYYN
[59]CoalNYYYWheat strawNYYY
[151]NG (methane)NNNNWaste woodNYYY
[152]Bituminous coalNYYYThree biomass typesNYYY
[21]High rank bituminous coalNYYYWhite and black pelletsNYYy
[153]CoalNYYNOlive wasteNYYN
[40]CoalM, SYYNPine sawdustM, SYYN
[154]LigniteM, SYYYPoultry litter, raw and torrefiedM, SYYY
[27]Two low quality coalsNYYYTwo RDF typesNYYY
[155]Bituminous coalNYYYFour woody biomass typesNYYY
[48]Slurry cake—waste coalM, SYYYMSW components and used turbine oilM, SYYY
[156]Shale coalMNNYThree biomass typesMNNY
[157]Two coalsMYNYBiomass from phytoremediationMYNY
[158]PeatNYYYWheat branNYYY

Reference [5] [159] [160] [160] [161] [162] [163] [164] [165]
Process, Equipment Laboratory Screw Pyrolyzer Batch Fixed Bed Gasifier + Secondary Catalytic Reactor Fixed Bed Pyrolyzer Auger Pyrolyzer Pilot Plant Full Scale Dual Fluid Bed Gasifier Laboratory Pyrolyzer—TGA Apparatus Laboratory Gasifier Laboratory Gasifier
Feedstock Pine Needles RDF Forestry Waste Waste Tires Woody Biomass Wood Pellets Elephant Grass Waste Tires + Plastics + Biomass Wood Pellets
Gas Composition, % vol. Component Yield, % wt. of Dry Biomass Gas Composition, % vol.
H25.3324.02.312.039.639.904.33.57
N256.41------56.767.51
CO15.8920.043.920.022.824.06.65.615.3
CO212.0010.141.88.020.925.218.67.910.8
CH49.222.79.67.49.88.60.63.72.82
C2H41.151.70.910.73.12.00.10.1-
Other-41.51.541.93.80.30.2--

Ref. Layout Performance Indicator Biomass Share, %
[37]140 t/h steam boilerBE≤20 thermal
[33]18.7 MWe plantspecific fuel consumption≤60 by mass
[13]Multiple systemsBE≤100
[114]Simulated co-firing power plantBE, PE≤30 by mass
[115]Spanish coal fired power plantsBE, PE≤17 by mass
[119]Biomass gasifier + gas reburning in flue gas of coal combustionBE≤46 thermal
[57]500 MWe coal boiler, CFD simulation data from boiler simulation≤100
[85]0.75 MWt CFB combustorBE≤23 by mass
[84]1 MWt CFB system with chemical looping for CO2 captureCarbon capture efficiency≤50 by mass
[129]1000 MWe supercritical oxyfuel power plant with CC modeled in ChemCADnet electric efficiency≤100
[20]Pulverized coal boiler, CFD calculations + Aspen PlusBE≤100
[130]Model calculation of energy consumption and CO2 LCA for biomass co-firingenergy consumption for supply chain, biomass pretreatNot provided
[132]Laboratory drop tube furnacecombustion efficiency≤50 by mass

Ref. VS Combustion Process Aspects Ash
OC AS REB AE 1 2 3 4 5 6 7 Other 8 9
[18]YNNNNNNNYNNNYYY
[17]YNYNNYYYYNNNNNN
[104]YNYYYNNNNNNNYNN
[19]YNNNNYNNNNNNYYY
[105]YNYNNYYYYNNNYYY
[8]YNNNNYYYYYYYYYY
[44]YNYNNYNNYNNNNYN
[82]YNNNYNNNYNNYYYN
[106]YNYNNYYNYNNNYYY
[35]NNNNNYNYNNNYYNY
[107]NNNNNNNNYNYYNNN
[37]YNNNNYNNNNNNNYN
[108]YNNNNNNNYNNYYNN
[36]YNNNNYNNNNNNYYN
[33]YNYNNNNNNNNNNNN
[13]YNNNNYYYYNNNYYY
[109]YYNNNNNNYYNNYNN
[32]YNNNNYYNNNNNNNN
[110]YNNYYNNNNNNNYNN
[111]YNNYNNNNYNNNYNN
[51]YNNNNYYYYNNNNYY
[112]YNNYYNNNNNNNYNN
[114]YNNNNNNNNNNNNYN
[115]YNNNYNNNNNNYNYN
[116]YYNNNNNNYYNNYNN
[117]YNNNNNNNNYNYNNN
[118]YYNNNNNNYYNNNNN
[119]NNNYYNNNNNNNNNN
[57]NYNNNNNNNNNYYNY
[120]YNYNNYYNYNNYYYY
[31]YNYYNYYNNNNNNNN
[121]YNYNNNNNYNNNNNN
[11]NNNNNNNNNNNNNYY
[10]YNNNNYYYNNNNYNY
[86]YYNNYYYNYNNNYYN
[122]NNNNYNNNNNNNYYY
[123]YYYNNNNNYNNYYNN
[124]YYNNNNNNNNNYYNN
[41]YYNNNNNNNNNNYNN
[125]YNNNYNNNNNNYYNN
[25]YYNNNNNNNYNNYNY
[38]YNNNNNYNNNNNYYY
[49]YNYNNNNNYNNYNNN
[126]YNYYYNNNNNNNYYN
[58]NNNNNNNNNNYYYNN
[127]NNNNNYYNNNNYNYY
[103]NNNNNYYNNNNNNNN
[78]YNNNNNNNNYYNNNN
[85]NNNNYNNNYNNYYYN
[84]NNNNNNNNNNNNYNN
[128]YNNNYNNYNNNNNYN
[129]YYYNYNNNNNNNYNN
[42]YYNNYNNNNNNNYYY
[20]NNYNNNNNYNNYYNN
[26]YNNNNNNNNYYNYNN
[131]NNNNNNNNNNNYYNN
[132]YNNNNNNNNNNNNYN
[91]YNNNNNNNNNNNYYY
[22]YNNNNNNNNYYNYNN
[133]YNYYYNNNNNNYNNN
[134]NNNNNNNNNYNNYYN
[71]YNNNNNNNNNNNYYN
[45]NNNNNNNNNNNYNYN
[50]YNNNNNNNNYNNYYY
[63]YYNNNNNNNNNNNNN
[136]YNYNNNNNYNNYYNN
[23]YNYNNYYNYNNNYYY
[28]YNNNNNNNNNNNYYY
[137]YNYNNNNNNNYYYNN
[138]YNNNNNNNNYYNYNN
[139]YNNNNNNNNNNNNYY
[140]YNNNNNNNYNNNNNN
[47]YNNNNNNNNYYNNYN
[141]YNNNNNNNNNNNYYN
[39]YNNNNYNNNNNNYYY
[142]YYYNNNNNNNNYYNN
[143]YNNNNNNNNYYNNYN
[43]YNNNNNNNNNNYYNN
[83]YNNNNNNNNYYNNNN
[144]NNNNNYYNNNNNYYY
[145]YNNNNYYNNNNYYYY
[90]YNNNNNNNNNNNYYY
[46]YNNNNNNNNYYNYYY
[146]NNNNNYYNNNNYYNN
[147]YNNNNYYNNNNNYYY
[148]NNNNNNNNNYYNYNN
[88]YNNNYYYNNNNNYYY
[24]YNNNNNNNYYYNYNN
[149]YNYNNNNNYNNNYNN
[150]YNNNNNNNNYYNNYY
[29]NNYNNNNNNNNNYYN
[59]NNYNNNNNYNNYYNN
[151]YNYYYNNNNNNYYNN
[152]YNNNNNNNNNNNYNN
[21]YNNNNYYNYNNYYYN
[153]YYYNNNNNNNNYYNN
[40]YNNNNYYNNNNNYYY
[154]YNNNNNNNNYYNNNN
[27]YNNNNNNNNYYNNNN
[48]YNNNNNNNNYNNYNN
[156]YNNNNNNNNYNNYNN
[157]YNNNNNNNYYNNNNN
[158]YNNNNNNNNYNNYYY

Ref. GHG Emissions Other Emissions
NOx SOx CO Other Metals Chlorides Other
[18]YYNNNNN
[17]YYYYYYY
[104]YNNNNNN
[19]YNNNNNN
[105]YYNYYYY
[64]YYNYYNN
[8]YYYNNYN
[65]Y eqY eqY eqY eqYNY
[44]YYYYYNY
[82]YNYNNNN
[106]YYNNNNY
[89]YNNNNNN
[35]YYNNNNN
[107]YNNNNNN
[36]YYYYYYY
[33]YYNNNNN
[13]YYYYYYY
[32]YYNYYNN
[110]YNNNNNN
[111]YNYNNNN
[51]NNNNYYY
[112]YNNNNNN
[113]NNYYNNN
[114]Y eqY eqY eqY eqNNN
[68]YYYYNNN
[119]YNYNNNN
[120]YYYYNNN
[31]YYNNNNN
[121]YNYNNNN
[11]YYNNNNN
[10]YYYYNNN
[86]YYNNNNN
[41]YNNNNNN
[125]YNYNNNN
[49]YNNNNNN
[69]YYNNNNN
[126]YNYNNNN
[58]NYYNNNN
[127]YYYYNNN
[85]YYYYNNN
[84]YYNNNNN
[56]Part of CO2 LCA, recalculated to CO2 equivalent
[52]YYYYNNN
[42]YYYYNNN
[20]YYYNNNN
[132]YYYYNNN
[91]YYNNNNN
[22]YYYNNNN
[133]YNNNNNN
[134]YYYNNNN
[71]YYYNNNN
[45]NNNNYNY
[135]YYYYNNY
[136]YNYNNNN
[23]YYYNNNN
[137]NNYYNNN
[138]NNNYYNN
[70]Part of CO2 LCA recalculated to CO2 GWP equivalent
[140]YYNNNNN
[142]YYYYNNN
[43]YYYNNNN
[46]NNNNYNN
[146]YYNYNNN
[149]NYYNNNN
[29]YYYNYNN
[59]YNNNNNN
[151]YNNYNNN
[152]NNYYNNN
[153]YNYNNNN
[155]YYYYNNY
[48]YYYNNNY
[156]NYYNNNN
[157]YYNNNNN

Author Contributions

Conceptualization: M.V., J.K. and L.L.; methodology: M.V., A.V. and G.J.; investigation: J.J.; Data Curation: M.V. and O.M.; writing-original draft preparation: M.V. and J.K.; writing-Review and Editing: M.R. and O.M.; visualization: J.J.; funding acquisition: A.V. and M.R. All authors have read and agreed to the published version of the manuscript.

Funding

This work was financially supported by the Slovak Research and Development Agency under the contracts Nr. APVV-19-0170, APVV-16-0192 and APVV-15-0148.

Institutional Review Board Statement

Not applicable.

Informed Consent Statement

Not applicable.

Data Availability Statement

Data sharing not applicable.

Conflicts of Interest

The authors declare no conflict of interest.

Abbreviations

adair dry (feedstock composition analysis)
AEvariable air/oxygen excess (Table 9)
aras received (feedstock composition analysis)
ASair staging
BEboiler efficiency %
BESP breakeven electricity selling price
BFbatch furnace
BGbiomass gasifier
B+Wbiomass plus waste (feedstock type, Table 5)
Cmodeling/calculation approach, Table 5
CAPEXcapital expenses
CBcoal boiler
CCcarbon capture
CFBcirculating fluidized bed
CFBCcirculating fluidized bed combustor
CFDcomputational fluid dynamics
CLCchemical looping combustion
Ddrying (feedstock pretreatment, Table 5)
dafdry ash free basis (feedstock composition analysis)
dbdry basis (feedstock composition analysis)
DTFdrop tube furnace
DTGAdifferential thermogravimetric analysis
Ec.economic
ECLIPSE European Coal Liquefaction Process Simulation and Evaluation simulation software package
EconPeconomic performance
EFRentrained flow reactor
Ene.energy
EnePenergy performance
Env.environmental
Eq.emissions recalculated to CO2 equivalent as a part of CO2 LCA
EUEuropean Union
Ffurnace
FBfluidized bed
FBBfluidized bed boiler
FBCfluidized bed combustor
Fos. fossil (feedstock, Table 5)
FSfull scale (system, equipment)
Ggasification (feedstock pretreatment, Table 5)
GHGgreenhouse gases
GWPglobal warming potential
HHVhigher heating value MJ/kg
IBindustrial boiler
IFRisothermal flow reactor
Llaboratory (system scale, Table 5)
LCAlife cycle assessment
LHVlower heating value
Mmilling (feed preparation, Table 6); more (feed types, Table 5); multiple (systems, system scales, Table 5)
MGmoving grate (type of combustor or boiler)
MIAmulti-instrumental analysis
MWeMegawatts of electric power output
MWtMegawatts of thermal power input
NGnatural gas
NGCCnatural gas fired combined cycle
NPVnet present value
Ooriginal (paper type, Table 5)
OCoxycombustion
OPEXoperational expenses
Ot.other (feedstock pretreatment, Table 5)
Ppilot plant (system scale, Table 5), pelletizing (feed preparation, Table 6)
PCBpulverized coal boiler
PEplant efficiency %
PFBApressurized fluidized bed apparatus
PFCpulverized fuel combustor
PFFpulverized fuel furnace
PIperformance indicator
PMparticulate matter
PPBpower plant boiler
PYpyrolyzer
Rreview (paper type, Table 5)
RDFrefuse derived fuel
REBreburning
Ssieving (feed preparation, Table 6), single (feedstock type, Table 5)
SCRselective catalytic reduction system
Sh.shredding (feed preparation, Table 6)
SPRsingle particle reactor
Subbit.subbituminous (coal)
Ttorrefaction (feedstock pretreatment, Table 5)
TFtube furnace
TGAthermogravimetric analysis
TICtotal investment cost
UGButility grate boiler
Vvarious (feedstock pretreatment techniques, Table 5)
VOCvolatile organic compounds
VSvariable biomass/waste share

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AuthorAffiliation

Miroslav Variny

1,*,

Augustín Varga

2,

Miroslav Rimár

3,

Ján Janošovský

1,

Ján Kizek

3,

Ladislav Lukáč

2,

Gustáv Jablonský

2 and

Otto Mierka

1

1Department of Chemical and Biochemical Engineering, Faculty of Chemical and Food Technology, Slovak University of Technology in Bratislava, Radlinského 9, 812 37 Bratislava, Slovakia

2Department of Thermal Technology and Gas Industry, Institute of Metallurgy, Faculty of Materials, Metallurgy and Recycling, Technical University of Kosice, Letná 9, 042 00 Košice, Slovakia

3Department of Process Engineering, Faculty of Manufacturing Technologies of the TU of Kosice with a Seat in Prešov, Technical University of Kosice, Štúrova 31, 080 01 Prešov, Slovakia

*Author to whom correspondence should be addressed.

Word count: 16180

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© 2021. This work is licensed under http://creativecommons.org/licenses/by/3.0/ (the “License”). Notwithstanding the ProQuest Terms and Conditions, you may use this content in accordance with the terms of the License.

Abstract

Co-combustion of biomass-based fuels and fossil fuels in power plant boilers, utility boilers, and process furnaces is a widely acknowledged means of efficient heat and power production, offering higher power production than comparable systems with sole biomass combustion. This, in combination with CO2 and other greenhouse gases abatement and low specific cost of system retrofit to co-combustion, counts among the tangible advantages of co-combustion application. Technical and operational issues regarding the accelerated fouling, slagging, and corrosion risk, as well as optimal combustion air distribution impact on produced greenhouse gases emissions and ash properties, belong to intensely researched topics nowadays in parallel with the combustion aggregates design optimization, the advanced feed pretreatment techniques, and the co-combustion life cycle assessment. This review addresses the said topics in a systematic manner, starting with feed availability, its pretreatment, fuel properties and combustor types, followed by operational issues, greenhouse gases, and other harmful emissions trends, as well as ash properties and utilization. The body of relevant literature sources is table-wise classified according to numerous criteria pertaining to individual paper sections, providing a concise and complex insight into the research methods, analyzed systems, and obtained results. Recent advances achieved in individual studies and the discovered synergies between co-combusted fuels types and their shares in blended fuel are summed up and discussed. Actual research challenges and prospects are briefly touched on as well.

Details

Title
Advances in Biomass Co-Combustion with Fossil Fuels in the European Context: A Review
First page
100
Publication year
2021
Publication date
2021
Publisher
MDPI AG
e-ISSN
22279717
Source type
Scholarly Journal
Language of publication
English
DOI
https://doi.org/10.3390/pr9010100
ProQuest document ID
2476384986
Copyright
© 2021. This work is licensed under http://creativecommons.org/licenses/by/3.0/ (the “License”). Notwithstanding the ProQuest Terms and Conditions, you may use this content in accordance with the terms of the License.