Why is There a Continual Bleed to Fuel From the Recycle Gas Rather Than Recycling All of the Gas

Steady State Simulation for Optimal Design and Operation of a GTL Process

Mehdi Panahi , ... Ramprasad Yelchuru , in Proceedings of the 2nd Annual Gas Processing Symposium, 2010

2.2 Syngas unit

In GTL processes, there are different routes for syngas production from natural gas, including Auto Thermal Reforming (ATR), steam reforming, partial oxidation of methane and CO₂ reforming. ATR is a combination of steam reforming and oxidation of methane. It is claimed to be the best route for syngas production (Bakkerud, 2005) and has been selected for this study.

To avoid the potential problem that the ATR works as a steam cracker, producing olefins from higher hydrocarbons in the feed, an adiabatic pre-reformer is introduced. Here, the temperature is 350–550   °C and all higher hydrocarbons are converted (Aasberg-Petersen et al, 2001) according to the following reactions: Complete conversion reactions (endothermic, so energy is needed):

(1) $C_2{H}_6+2H_{2}O\to 5H_2+2\mathit{CO}\Delta H=+350\frac{\mathit{kJ}}{\mathit{mol}}\Delta G=+201.86\frac{\mathit{kJ}}{\mathit{mol}}$

(2) $C_3{H}_8+3H_{2}O\to 4H_2+3\mathit{CO}\Delta H=+500\frac{\mathit{kJ}}{\mathit{mol}}\Delta G=+302.78\frac{\mathit{kJ}}{\mathit{mol}}$

(3) $C_4{H}_{10}+4H_{2}O\to 9H_2+4\mathit{CO}\Delta H=+650\frac{\mathit{kJ}}{\mathit{mol}}\Delta G=+403.71\frac{\mathit{kJ}}{\mathit{mol}}$

Equilibrium reactions:

(4) $\mathit{CO}+3H_2\iff C{H}_4+H_{2}O\Delta H=-210\frac{\mathit{kJ}}{\mathit{mol}}\Delta G=-151.65\frac{\mathit{kJ}}{\mathit{mol}}$

(5) $\mathit{CO}+H_{2}O\iff C{O}_2+H_2\Delta H=-41\frac{\mathit{kJ}}{\mathit{mol}}\Delta G=-19.09\frac{\mathit{kJ}}{\mathit{mol}}$

In our case, natural gas and water are preheated to 455   °C and fed to the adiabatic prereformer. In spite of the exothermic equilibrium reactions the overall reactions are endothermic and the outlet temperature is about 416   °C.

The pre-reformer outlet stream is mixed with recycled flue gas from the FT unit and heated in a fired heater to 675  °C before entering the adiabatic authothermal reformer (ATR). Oxygen is preheated to 200   °C and is also fed to the ATR. The ATR is the main reactor in producing the synthesis gas and the following three main reactions take place:

Oxidation of methane (exothermic):

(6) $C{H}_4+\frac{3}{2}{O}_2\iff \mathit{CO}+2H_{2}O\mathrm{\Delta }H=-520\frac{\mathit{kJ}}{\mathit{mol}}\mathrm{\Delta }G=-562.65\frac{\mathit{kJ}}{\mathit{mol}}$

Steam reforming of methane (endothermic):

(7) $C{H}_4+H_{2}O+210\frac{\mathit{kj}}{\mathit{mol}}\iff \mathit{CO}+3H_2\mathrm{\Delta }H=+210\frac{\mathit{kJ}}{\mathit{mol}}\mathrm{\Delta }G=+151.65\frac{\mathit{kJ}}{\mathit{mol}}$

Shift Reaction (exothermic):

(8) $\mathit{CO}+H_{2}O\iff C{O}_2+H_2\mathrm{\Delta }H=-41\frac{\mathit{kJ}}{\mathit{mol}}\mathrm{\Delta }G=-19.09\frac{\mathit{kJ}}{\mathit{mol}}$

Because of the large heat generated by combustion in reaction (6) the net reactions are exothermic, and the outlet temperature of the ATR is about 1000   °C.

A high-pressure CO₂ capturing process with MDEA as an absorbent is used to remove most of the CO₂ from the syngas. A mixture of hydrogen and carbon monoxide is the main product of ATR and a ratio of $\frac{H_2}{\mathit{CO}}$ around 2–2.3 is desired to have maximum conversion to liquid fuels in the subsequent FT reactor (see Fig. 2). To set this ratio, a small amount of CO₂ is recycled to the ATR. This avoids that too much CO is shifted to CO₂ according to reaction (8).

Figure 2. Effect of %CO2 removal on (1) H2/CO in syngas and (2) production of liquid fuels

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Oxy-fuel heat transfer characteristics and impacts on boiler design

Y. Liu , ... R. Gupta , in Oxy-Fuel Combustion for Power Generation and Carbon Dioxide (CO2) Capture, 2011

9.2.2 The relationship between recycle ratio and oxygen (O₂) concentration

The absence of nitrogen in oxidant reduces the flue gas volume and recycled flue gas is used to compensate for the absence of nitrogen. By increasing recycled flue gas to about 77% in wet recycle oxy-fuel, the same volumetric flue gas flow rate as in air-firing is achieved. At the same recycle ratio, dry recycle oxy-fuel results in a lower gas flow rate than wet recycle because water vapor is removed.

By increasing proportions of flue gas recycled from 50% to 80%, oxygen concentrations at burner inlet decrease from 53% to 24% and 45% to 19% for dry recycle and wet recycle conditions respectively, as indicated in Fig. 9.3. The higher oxygen concentration for dry recycle is due to the absence of the water vapor dilution that exists in the wet recycle. The oxygen required to completely combust coal is defined as theoretical oxygen required. In practice the oxygen supply is greater than this theoretical value to achieve complete burnout; thus excess oxygen is defined as the ratio of oxygen excessively supplied to the theoretical oxygen requirement. Excess oxygen comes partly from the pure oxygen stream from the air separation unit and partly from recycled flue gas, the contribution from the recycled flue gas being the greater. Excess oxygen at burner inlets increases with increasing recycled flue gas for recycle flue gas containing 3.3% oxygen. When 71% of flue gas is recycled, 15.9% and 12.6% excess oxygen at burner inlets is obtained for wet and dry recycle oxy-fuel combustion respectively. The higher excess oxygen in wet recycle than in dry recycle oxy-fuel is due to higher excess oxygen from the air separation unit outlet in wet recycle, when both recycle modes achieve 3.3% oxygen in the flue gas.

9.3. Oxygen concentrations (% v/v) and excess oxygen (oxygen at burner/stoichiometric oxygen for fuel) at burner inlet, excess oxygen for air separation unit (oxygen supplied by ASU/stoichiometric oxygen for fuel) as a function of recycled flue gas ratio in oxy-fuel combustion.

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Coal and biomass cofiring

María V. Gil , Fernando Rubiera , in New Trends in Coal Conversion, 2019

5.7 Oxy-fuel cofiring

Oxy-fuel combustion is a technology for the GHG abatement. In this technology, fuel is combusted with the aid of a mixture of oxidizer and recycled flue gas, which provides a rich stream of CO ₂. This technology has mainly been widely used for coal combustion (Kanniche et al., 2010; Nakod et al., 2013; Rebola and Azevedo, 2015; Riaza et al., 2011; Singh et al., 2013), but the literature is scarce for biomass cofiring.

An experimental study evaluated the ignition and burnout performance of coal and biomass mixtures in oxy-fuel conditions using an entrained flow reactor (EFR) (Arias et al., 2008b). The results showed that the ignition temperature had strong dependence on the combustion environment. A delay in the ignition was observed for the burning with a mixture of 79%CO₂–21%O₂ compared with air firing. This significantly affected the flame temperatures. When the O₂ fraction in the CO₂/O₂ mixture was higher than 30%, early ignition took place at comparatively lower temperatures. It was concluded that the use of biomass blend has a low impact during air combustion, but a significant improvement in the burnout of the coal/biomass blends was found under oxy-fuel cocombustion conditions.

The ignition temperature, burnout, and NO emissions of blends of a semianthracite and a high-volatile bituminous coal with 10–20   wt.% of olive waste have also been studied under oxy-fuel combustion conditions in an EFR (Riaza et al., 2012). A significant reduction in ignition temperature and a slight increase in the burnout value were observed after the addition of biomass, this trend becoming more noticeable as the biomass concentration increased. Emissions of NO were significantly reduced by the addition of biomass to the bituminous coal, although this effect was less noticeable in the case of the semianthracite.

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Sustainable Energy Technologies & Sustainable Chemical Processes

Shijie Liu , ... Bin Liang , in Encyclopedia of Sustainable Technologies, 2017

Bubbling-bed pyrolyzer

Crushed biomass (2–6 mm) is fed into a bubbling bed of hot sand or other solids. The bed is fluidized by an inert gas such as recycled flue gas. Intense mixing of inert-bed solids offers good and uniform temperature control. It also provides high heat transfer to biomass solids. The residence time of the solids is considerably higher than that of the gas in the pyrolyzer. The required heat for pyrolysis may be provided either by burning a part of the product gas in the bed or by burning the solid char in a separate chamber and transferring that heat to the bed solids. The pyrolysis product would typically contain about 70%–75% liquid on dry wood feed.

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NOx Emissions During Oxycoal Combustion

Dobrin D. Toporov , in Combustion of Pulverised Coal in a Mixture of Oxygen and Recycled Flue Gas, 2014

7.2 Influence of the excess oxygen ratio at the burner

The NO _x emission characteristics of the three cases, (1) air mode; (2) ${\mathrm{O}}_2/{\mathrm{CO}}_2$ mode; and (3) ${\mathrm{O}}_2/\text{RFG}$ mode, were evaluated among several conditions of the excess oxygen ratio at the burner. The oxygen concentration at burner inlet was set to 21   vol% for all of the combustion modes. The flow rate of the gas mixture was kept constant. The excess oxygen ratio at the burner was varied by controlling the coal feed rate. The excess oxygen ratio $\lambda$ is defined as follows:

(7.1) $\lambda =\frac{m_{{\mathrm{O}}_2}/m_{\mathrm{fuel}}}{{(m_{{\mathrm{O}}_2}/m_{\mathrm{fuel}})}_{\mathrm{stoichiometric}}}$

Here the ratio $m_{{\mathrm{O}}_2}/m_{\mathrm{fuel}}$ gives the mole ratio of oxygen to fuel. The conversion ratio (CR in %) of fuel-N to NO _x is calculated as follows:

(7.2) $\mathit{CR}={\text{NO}}_{x_{\mathrm{stack}}}/{\text{NO}}_{x_{\mathrm{total}}}\times 100$

where ${\mathrm{NO}}_{x_{\mathrm{stack}}}$ is actual NO _x measured at the stack in mg/MJ (containing the fuel NO _x and thermal NO _x ), and ${\mathrm{NO}}_{x_{\mathrm{total}}}$ is total NO _x , which theoretically could be emitted when all fuel N was converted to NO _x , in mg/MJ. Figure 7.1 shows the influence of the excess oxygen ratio at the burner upon conversion to NO _x during the three different operation modes. There is an obvious trend of increase in NO _x emissions with increase of the burner excess oxygen ratio. This trend is valid for all three combustion modes.

In air mode, the NO _x emissions with this burner are significantly higher than emissions obtained with state-of-the-art low-NO _x burners. The reason for this behaviour is twofold. First, the walls of the test facility are heated in order to obtain an adiabatic furnace so that NO _x emissions cannot be simply compared to an industrial application. Second, the burner has been optimised for oxyfuel combustion by inducing a strong inner recirculation of hot flue gas, which is necessary to ignite the reactants under oxyfuel conditions (Type 2). This causes high temperatures in the burner vicinity and thus favours the formation of thermal NO.

In ${\mathrm{O}}_2/{\mathrm{CO}}_2$ mode, the conversion to NO _x is about 25% to 30% lower than in air mode.

For the ${\mathrm{O}}_2/\text{RFG}$ mode, the conversion of fuel N is much lower compared to other combustion modes, reaching a reduction by approximately 50% compared to ${\mathrm{O}}_2/{\mathrm{CO}}_2$ mode. This is mainly due to the fact that NO _x contained in RFG is supplied by the secondary stream back to the flame, and, thus, it is destructed by reducing conditions due to volatile matter.

The general trend to increase NO _x emissions with increased burner oxygen ratio in oxyfuel combustion shown by Kiga et al. [220] for an oxidiser oxygen concentration of 30   vol% can be confirmed with the current experiments for an oxygen concentration of 21   vol%.

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Oxy-fired fluidized bed combustion: technology, prospects and new developments

E.J. Anthony , H. Hack , in Fluidized Bed Technologies for Near-Zero Emission Combustion and Gasification, 2013

19.3.4 SO₃ emissions

The issue of SO₃ emissions, given its potential to cause corrosion, is something which is of interest for oxy-fuel systems, for two reasons, namely the use of recycled flue gases will likely increase SO₃ levels, and potentially high oxygen concentrations, particularly at the base of the bed, might also enhance its formation. There is currently a dearth of information on this subject for oxy-FBC systems; however, from preliminary research done by CanmetENERGY on its 0.8   MWth CFBC, levels do not seem excessive (Table 19.5) (Jia et al., 2012c), albeit that the bituminous coal contains only 0.53% sulphur. Ahn et al. (2011) have also recently examined SO₃ concentrations for a 1.5   MW pilot-scale PC combustor and a 330   kW pilot-scale circulating fluidized bed test facility using: a PRB coal with 0.2% sulphur; a Utah coal with 0.5% sulphur; and an Illinois coal with 4% sulphur. Unfortunately, they appear only to have examined SO₃ levels for the Utah coal for which they conclude that SO₃ levels are similar for both air- and oxy-firing under their conditions. They also point out that the presence of particles may provide more opportunities for SO₃ formation via catalytic processes, but note that SO₃ concentrations do not appear to be noticeably affected by the amount of limestone addition.

Table 19.5. SO₃ concentrations in the exhaust flue gas of a 0.8   MWth CFBC oxy-fuel pilot plant

20% wood/80% bituminous coal	<0.16   ppmv
35% wood/65% bituminous coal	2.23   ppmv
50% wood/50% bituminous coal	1.12   ppm

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Modeling of Solid and Bio-Fuel Combustion Technologies

Arafat A. Bhuiyan , ... Jamal Naser , in Thermofluid Modeling for Energy Efficiency Applications, 2016

11.7.3 Effect of Different Performance Parameters

Four different combustion environments were investigated in this study. They are: air combustion (23% inlet O₂) (case-I) shown as the reference case and three different RFG fuel (oxy-fuel) combustions such as RR 75% (22.8% inlet O₂), RR 72% (25.4% inlet O₂) and RR 65% (30.9% inlet O₂). The feed gases for these combustion environments are summarized in Table 11.7. In all the combustion cases, some variables were always kept constant, such as input power of 0.5   MW, initial conditions (pressure=101,325   Pa, temperature=800   K, ρ=0.67   kg   m⁻³). The mass flow rate of coal was also constant for all the air and oxy-fuel combustion cases. In the experiments, for the oxy-fuel cases, a dry recycle system was simulated where the O₂ concentration in the primary transport was maintained at a constant value. A similar condition was maintained in the present numerical analysis.

The velocity vector (m   s⁻¹) at the inlet for the air-firing case is shown in Figure 11.10. In order to increase the mixing, stabilize the flame shape and to provide enough time to the oxidizers for complete burning of fuel, the swirled flow is used in the burning systems. The swirl effect is significant in the combustion phenomenon. The primary oxidizer and the coal particles are fed into the furnace through a primary inlet and swirled secondary oxidizers are fed through a secondary air inlet as shown in the burner configuration. The velocity vectors show an internal recirculation zone, reaction zone, and external recirculation zone. The velocity distributions on the axial vertical position at 0.3   m from the burner exit for selected cases are presented in Figure 11.10. From the figure, it is seen that the velocity of oxidizing gas is decreasing from reference case to RR 65% case. This provides more residence time for the fuel particle to stay in the combustion reaction area and thus a better ignition environment which finally improves the flame temperature.

Figure 11.10. Flow visualization in combustion modeling for different cases.

Figure 11.11 shows the temperature distributions for different cases considered. The variation in the flames' shape between air-fired and RFG fuel-fired cases can be explained on the basis of the differences in the thermodynamics behavior between N₂ present in air-firing and CO₂ present in oxy-fired cases. The flame temperature for the case of RR 72 is very much similar to that of the air-combustion case. But the flame temperature for RR 75 is slightly lower than the air-fired case. This is due to reduced O₂ in RR 75 compared to the air-fired case and availability of CO₂ in RR 75. Comparatively more luminous flames are seen in cases RR 75, RR 72, and RR 65. For a lower RR of 65%, much brighter flame is observed compared to the air case. It is clear that the flame temperature increases when oxygen in the inlet is higher and the RFG is less. The flame temperature for the case of RR 65 is higher compared to RR 72 and RR 75.The maximum flame temperatures for air-fired, RR 75, RR 72, and RR 65 were 2250, 2100, 2280, and 2585   K, respectively. This phenomenon may be explained on the basis of the characteristics of turbulent timescale of the EBU combustion model, which suggests a higher flame temperature in the RFG environment with O₂-enriched cases due to the quick combustion rate.

Figure 11.11. Flame temperature (K) distribution at a position 0.3   m from the burner exit.

Availability of oxygen (O₂) mass fraction (kg   kg⁻¹) in the exit of the burner area contributes to the flame characteristics and the ignition environment. The O₂ mass fraction (kg   kg⁻¹) on a horizontal plane axially along the center of the furnace is shown in Figure 11.12 for different cases. This figure graphically illustrates the O₂ mass fraction for the air-fired and three RR cases. It is seen from the figure that the O₂ concentration for the air-fired case is similar to that of RR 75 case. Some delay can be observed in the consumption of oxygen (O₂) in the air case and RR 75. For RR 72 and RR 65, the profile is more or less similar to the RR 75% case, but the O₂ concentration is slightly higher. However, the consumption of O₂ is faster and the availability of O₂ is much enriched in the case of RR 65% compared to RR 72% and RR 75%, so the ignition condition is improved and better flame is observed just after the exit of the burner. CO₂ mass fractions are presented in Figure 11.13 displaying the comparisons of the mass fraction distributions (kg   kg⁻¹) of CO₂ for all the cases. In the case of air firing, the maximum CO₂ concentration in the furnace is 0.193 by mass (kg   kg⁻¹). In the case of higher RR, CO₂ is much more enriched. But for lower RR 65% cases, this fraction goes down to approximately 0.88 by mass. According to chemical properties [117], CO₂ has higher specific heat compared to nitrogen (N₂). This property is responsible for absorbing more heat, which protects the furnace wall and controls the overall emissivity. That is why an increase in CO₂ in the RR cases has significant importance in the combustion environment compared to the air-fired case. The species mass fraction distribution for different cases at 0.3   m from the burner exit is presented in Figure 11.14.

Figure 11.12. Oxygen (O₂) mass fraction distribution (kg   kg⁻¹) for different cases.

Figure 11.13. Carbon dioxide (CO₂) mass fraction distribution (kg   kg⁻¹) for different cases.

Figure 11.14. Different species mass fraction distribution at 0.3   m from the burner exit.

The predictions of the radiation for all combustion cases in the radiative sections are calculated. The values of radiative heat flux for the RR 75, RR 72, and RR 65 cases are compared against the experimental case. The calculated radiative heat fluxes are in the range of 250–400   kW   m⁻², whereas for the RR 75, RR 72, and RR 65 cases, the range is 275–340, 270–365, 340–490   kW   m⁻², respectively. The variation in radiative heat flux with RR can be explained on the basis of an O₂-enriched environment. When, the O₂ concentration is increased by reducing the RR, the radiative heat flux at the radiative sections increases as the RR is reduced from 75% to 65% by volume at the inlet. When CO₂ in the boiler decreases, the C _p of the flue gas decreases and the temperature can be higher, thus resulting in higher radiative heat flux. The predicted radiative heat fluxes for RR 72 and RR 75 are similar to that of the air-firing case. While for 65% RR, comparatively higher radiative heat flux is observed. The comparison of predicted and experimental radiative heat flux is given in Table 11.8.

Table 11.8. Comparison of radiative heat flux (Sir) and carbon-in-ash (CIA, %) measurement

Case	Carbon in ash (CIA) (%)		Radiative heat flux (KW   m−2)
	Experimental	Numerical	Experimental	Numerical
Air firing	2.10	2.45	390.00	431.58
RR 75%	0.50	1.87	340.00	393.46
RR 72%	0.90	1.47	370.00	398.29
RR 65%	0.50	1.45	495.00	522.71

The variation of peak flame temperature for air operation to oxy-fuel operation with different RRs is presented in Figure 11.15. The figure shows that the peak flame temperature for air operation is equivalent to peak oxy-fuel flame temperature at an RR of approximately 72%, which is consistent with experimental results. The normalized radiative and convective heat fluxes for different RR are presented in Figure 11.15. In the case of radiative heat flux, peak values are considered. The graphical presentation shown can help in evaluating a suitable working range for coal combustion under varying RR conditions where both radiative and convective heat transfer can be maintained at a unique balance. This information will help in evaluating the performance of a newly built or an existing retrofitted furnace run on both air and oxy-fuel combustion.

Figure 11.15. Oxy-fuel operation to air operation, for different performance parameters [4].

In order to offer direction to the utility power firms to take cost-effective measures by reducing the unburned carbon in fly ash (CIA), it is important to measure the unburned CIA. Also, predicting unburned carbon in fly ash is a significant measure for determining the efficiency of coal combustion in a power plant. CFD modeling offers this opportunity to measure the CIA. One of the objectives of this study was to determine unburned carbon in ash (CIA) for different firing conditions. Table 11.8 compares the numerically calculated CIA percentage with experimental data. CIA at the particles exiting the furnace depends on several factors, such as the particle size distribution, oxygen concentration, and residence time. Numerical results exhibit a similar trend with the experimental ones, for example, improved burnout under oxy-fuel-firing conditions compared to air combustion. This can be attributed to longer residence times for the particles as well as to the higher oxygen concentration in the furnace.

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Oxy-fuel power plant operation

Y. Tan , in Oxy-Fuel Combustion for Power Generation and Carbon Dioxide (CO2) Capture, 2011

Abstract:

This chapter will provide a brief overview of some of the key issues facing an oxy-fuel power plant, e.g. integration of air separation units and flue gas compression trains, oxygen and recycled flue gas control as well as flue gas recycle strategies. Other important issues that will be discussed include effects of air ingress and flue gas egress, corrosion concerns and power plant maintenance. This chapter will also discuss plant control issues, such as transition between air-blown mode and oxy-fuel mode operations, load changes and plant start-up and shutdown. These issues have significant impact on the performance, safety, reliability and economics of any oxy-fuel power plant.

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Boiler Control System

Swapan Basu , Ajay Kumar Debnath , in Power Plant Instrumentation and Control Handbook (Second Edition), 2019

9.3.1.2.1 Function of Gas Recycling Damper (Fig. 8.34)

The steam temperature is measured at both the outlet legs of the reheaters and averaged after selection and voting to form the ultimate measured/process variable for this control loop. The control strategy utilizes the recycled flue gas flow to the furnace hopper by throttling the single gas recycling damper receiving the controlled input command from a temperature/flow cascade control action.

Fig. 8.34. Reheater steam temperature control by gas recycling damper.

The PID (temperature) controller employed for this purpose has a set point adjuster for setting the desired value of the reheat steam temperature control system. The controller output is then summated with another PID (flow) controller, the output of which signifies whether the requirement of gas recycling flow is satisfied. The gas recycling flow signal as measured forms the measured/process variable for this part of the control loop and the set point is derived from the main steam flow (as the load index), duly characterized to give the corresponding expected recycled flue gas flow. The (temperature) controller output trims the flow controller output to derive the required desired position of the gas recycling damper. This signal forms the set value of the position controller while the actual position of the damper is measured and connected to the position controller output, which is utilized to modulate the gas recycling damper.

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Torrefaction

Prabir Basu , in Biomass Gasification, Pyrolysis and Torrefaction (Second Edition), 2013

Torrefier Section

The torrefaction zone is designed in the same way but with an additional stipulation that it must provide the specified solid residence time for the biomass feed and required yield.

The volume, V _tor, of the torrefaction zone for the given residence time of and production rate, W _t, is:

(4.37) $V_{\mathrm{tor}}=\frac{\tau W_{\mathrm{t}}}{{\rho }_{\mathrm{bulk}}}$

The height of the torrefaction zone is therefore calculated from V _tor:

(4.38) $L_{\mathrm{tor}}=\frac{V_{\mathrm{tor}}}{A_{\mathrm{r}}}$

The space velocity of solid in the torrefier section is generally very low to allow the required torrefaction time in this zone.

Example 4.5

In Example 4.4 , hot gas from an oil burner is diluted by recycled flue gas to reduce its temperature to 300°C, and it is then fed into the bottom of the torrefier. Heating value of oil is 45.5  MJ/kg and the burner operates at 20% excess air with an efficiency of 95%. Take latent heat of vaporization as 2260   kJ/kg.

Neglecting all heat losses, find the amount of oil consumption and what fraction of flue gas needs to be recycled through the burner.

Given:

Specific heat of flue gas, C _g=1.13   kJ/kg   C

Specific heat of steam, C _v=1.89   kJ/kg   C

Specific heat of air, C _air=1.006   kJ/kg   C

Specific heat of raw biomass, C _b=1.46   kJ/kg   C

Specific heat of dry or torrefied biomass, C _d=0.269   kJ/kg   C

Specific heat of oil, C _oil=1.7   kJ/kg   C

Stoichiometric air–oil ratio=14.6

LHV of volatiles=1286   kJ/kg

Solution

Neglecting losses, we calculate the following.

Energy required for raising 0.566   kg (Example 4.4) of raw biomass to 100°C in preheater is calculated using Eq. (4.19):

$Q_{\mathrm{ph}}=0.566\times 1.46\times (100–20)=66.1\mathrm{kW}$

Energy required for evaporation of the 30% moisture (Example 4.4) in biomass in dryer section is calculated using Eq. (4.19):

$Q_{\mathrm{dry}}=(0.566\times 0.3)\times 2260=383.8\mathrm{kW}$

Energy required for heating 0.396   kg dried biomass (Example 4.4) to 280°C is calculated using Eq. (4.19):

$Q_{\mathrm{pd}}=0.396\times 0.269\times (280–100)=19.2\mathrm{kW}$

Total load=66.1+414.6+19.2=469.0   kW

So, Q _total=469   kW

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