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Modified Coal Combustion Reduces NOx Compliance Cost and Fuel Consumption A.Kravets, A.Favale, J.Barba, D.Ginzburg, (all Veritask Energy Systems, Inc.)

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1. Introduction.

The steady reduction of power generated by coal and the new tighter environmental regulations are bringing serious challenges for this power sector and coal market. Operating companies are facing difficult business/strategic decisions in response to such trends. Never before has there been a need to rethink current practices of the Best Available Retrofit Technologies (BART) as critical as they are today.

VESI is a technology company that does exactly that. It offers a wide spectra of cost effective near term and long term solutions for fossil fuel market. These solutions allow meeting current and future regulations on emissions and fuel utilization efficiency through innovative and cost-effective integration of the fossil power system while utilizing existing technologies. Unlike BART the solutions presented below deliver a reduction of all types of emissions and fuel consumption. Solutions are tailored to specific application and provide return on investment (ROI) based on the reduction of fuel and substantial reduction of operating expenses related to existing AQCS equipment.

In this article we describe one simple, near term solution for NOx reduction for coal-fired power plants. The solution is patented and derived from experiences collected over several decades of coal gasification and coal processing industries.

2. Costs of NOx Compliance and Penalties.

The most common means of NOx compliance today include Ultra- and Low NOx Burners (LNB), Combustion System/Burner Modifications, Selective Catalytic Reduction (SCR), Selective None-catalytic Reduction (SNCR).

Traditional Low and Ultra-Low NOx technology include sub-stoichiometric combustion of fuel in burner zone (StBZ) with the balance of air required for complete combustion added through separate air ports (OFA). This approach has reached its maximum physical potential. Figure 1 illustrates typical trends of NOx and Unburned Carbon variation versus burner zone stoichiometry

for high and medium-volatile bituminous coals [1]. It was found that NOx reduction trend slows down with most fuels to a specific optimum level and then the NOx trend vs. furnace stoichiometry reverses. The trend for unburned carbon (CIA - Carbon In Ash) rises up monotonously while StBZ reduces. Typically minimal NOx level indicated in the Figure 1 cannot be reached in practice due to multiple penalties associated with it. Among those are increase of a plant Heat Rate due to a) increase of CIA and Carbon monoxide (CO) above acceptable operating values, b) Increased parasitic power losses with combustion air

supply to OFA ports, c) excessive water-wall slagging that may cause boiler over-firing and/or increase of reheater water spray due to high temperatures leaving furnace.

Figure 1. Typical NOx and UBC Trends for Ultra Low NOx Combustion

B urner Z o ne Sto ichio metry, %100 1208060


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In addition, LNB cannot meet NOx emissions limits alone and require installation of post combustion technologies to do so. These technologies incur significant capital and operating cost and have further distressed unit heat rate. Table 1 provides a quick overview of average retrofit costs and penalties for coal fired units [2,3]

Table 1. Normalized Costs (2011$) of NOx Compliance and Heat Rate Penalty (Overview)

Technology1) LNB LNB+OFA SCR SNCR

Low High Low High Low High Low High

NOx Reduction, % 20% 30% 30% 50% 80% 90% 20% 30%

Specific Costs, $US/kW2) $15 $70 $30 $90 $ 250 $350 $15 $60

Heat Rate Penalty, % (Note 3) (Note 3) 0.54% 0.60% 0.78%

Note 1. Low and High costs correspond to unit sizes 1000 MW and 100 MW respectively, and include Wall-Fired and Tangentially Fired units only

Note 2. Costs information was collected from EIA Form 767 Note 3. No penalties were reported. Operator may choose to trade-off NOx reduction against fuel

efficiency. This would offset heat rate losses but result in increased costs of NOx compliance.

From Table 1 above one can conclude that implementing BART technologies has not only resulted in substantial capital costs but are damaging to the efficiency of the plant which exacerbates the operating cost through increased of fuel costs.

It is difficult to evaluate the overall impact on the industry, but according to the capital investment report [2] compiled off EIA forms 860/767 the investment into post-combustion NOX control projects between 2000 and 2016 has exceeded 32B$US. Almost 4B$US is expected to be spent between now and 2020. The referenced costs do not include LNB replacement and do not account for the increase in operating costs.

Competitive, cost-effective options for NOx control proposed below will make unit operation profitable by bringing fuel consumption back to the original (pre-implementation heat rates, if equipped with SCR/SNCR) or avoiding BACT technology costs all together while profiting from a reduced fuel consumption.

In order to understand the principles behind the technology a brief review of coal combustion, heat and material balances of the specific reactions for a steam power plant.

3. Coal Combustion and NOx Formation – Background

The mechanism and effect of the proposed NOx reduction technique depends on fuel type. Its effect on coals essentially differs from other type of fuels (gaseous and liquid) and alters coal combustion kinetics at every phase from preheat and volatilization to completed char burnout.

In engineering practice, the level of achievable NOx emissions by primary means of control, i.e. by combustion system correlates with coal rank or content of Fixed Carbon (FC) and /or Volatile Matter (VM). For instance, Figure 1 above illustrates substantially higher NOx emissions for mid-

volatile (mvb) vs. high-volatile Class B bituminous coals (hvBb) fired within same combustion system and conditions, having fuel nitrogen content on as-received basis 1.3% and 1.25%


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respectively. [1] In other words, higher rank coal (Anthracite, Semi-Anthracite) inherently generate more NOx than lower rank Bituminous coals. In the science of combustion, coal proximate composition FC, VM, as well as, inherent moisture (IM), have strong correlations with coal porosity or internal surface (S). Original coal porosity and correspondent initial internal (SO) vs. coal rank is shown in Table 2[10,12]. Here initial particle surface (S0) is measured by CO2 adsorption. Note SO is expressed in square meters per 1 gram (1g ≈0.002 Lb).

From data in Table 2 an obvious correlation between VM, (FC/VM) with the So or coal porosity can be made. Numerous combustion and gasification studies concluded that lower rates of NOx formation can be attributed to coals with higher porosity. This finding demonstrates a major agreement of scientific and practical experiences; data in Figure 1 illustrates this agreement where coal with higher VM (i.e. higher porosity) generates less NOx. Most importantly, these findings open a pass to a deeper understanding of processes affecting coal combustion rates and NOx emissions formation in particular.

The role of an internal particles surface on chemical reaction for any given coal depends primarily on oxygen availability, aerodynamic conditions and composition of oxidant (in particular CO2 and water vapor). There are three distinct zones (regimes) where combustion is controlled by one or

two mechanisms shown in Figure 2. It depicts typical relationship of

combustion reactions rates vs. particle temperature indicating three distinct zone of reaction rates associated with changes in kinetic regimes.

Zone III corresponds to combustion rates of particles exposed to very high temperature. Due to high temperature chemical reactions between particles and surrounding bulk gas goes very fast in an immediate vicinity of particles (boundary layer) and on the particles

Table 2. Coal Rank vs. Internal Particles Surface

Coal Rank FC/VM VM, % So, m2/g

(by-CO2) Porosity, %

(ar)

Mid-Volatile Bitum. (mvb) [10] 2.9 25.0 15 - 40 3.0 - 5.0 High-Volatile Bitum. (hvBb) [10] 1.5 37.0 85-150 15.0 – 20.0 High-Volatile Bitum. (Blind Canyon, UT) [12] 1.0 42.0 140 21.5 Lignite (N. Dakota)[12] 0.7 48.0 180 30.6

Figure 2. Three Major Combustion Zones a) Reaction Rate vs. Particle Temperature, b) Gaseous species concentration inside and outside the particles for each

Zone


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surface. The process is controlled primarily by diffusion of oxygen from a surrounding bulk gas volume. While reaction rates are high, only a small, external surface of a particle participates in chemical reactions heterogeneously, while homogeneous reactions in a boundary layer dominate the process. Distribution of any gas component present in a bulk gas may be as depicted in Figure 2b by line III. Under such kinetic conditions coal/char particle size and porosity monotonously getting smaller [13], due to consumption by chemical reactions and through a direct surface ablation (evaporation). The example of equipment operating in Zone III are turbulent burners used in utility boilers prior to introduction of New Source Performance Standard (NSPS). Then, such burners produced very high NOx emissions on order of 1 Lb/MMBtu.

Reactions of coal/char particles in Zone II typically taking place at temperatures above 1000oC (~1800oF) are controlled by diffusion of a bulk gases through the boundary layer and then by pore diffusion/adsorption/chemisorption deep inside particles (refer to line II on Figure 2b) where they react heterogeneously with an internal particle surface (the latter is by six orders of magnitude larger than external surface). The products of these heterogeneous reactions will continue to react with surface upon their exit (desorption) back to external surface and then react homogeneously in a boundary layer surrounding particle and beyond. Due to such kinetics, the role of the internal surface in overall burnout process considerably increases. Moreover, under Zone II condition particles internal surface for bituminous and subbituminous coals expand, often by 1.5 to 2+ times [11,12, 13] even for coals with low swell index. Lower chemical reaction rates in Zone II do not lead to increase in burnout time, as the reaction rates are compensated by the growth of particles internal surface participating in the process, as well as, due to catalytic effect on particles surface (see below) resulting in approximately 50% reduction of activation energy for char oxidation reactions [13]. The net effect on overall char consumption rate in Zone II may even result in sizable (~10%) increase due to other non-oxygen components that are present in a bulk gas [7] (See below for more details). The example of power/industrial application operating under conditions of Zone II are Entrained gasification, Integrated Gasification Combined Cycle (IGCC), and Low-NOx pulverized coal combustion. For the latter, in some localized flame/furnace sections particles may be exposed to temperatures corresponding Zone III [11].

Within temperature range characteristic for Zone I (less than 600oC/1100oF) the chemical oxidation is slow, which allows oxygen and other oxidant components be absorbed without reaction with internal surface resulting in about the same bulk gas concentration both inside and outside of particles. The example of power/industrial application operating under Zone I condition are fixed bed gasification and fluidized bed boilers.

Coal combustion involves two steps: 1) Thermal decomposition, de-volatilization, and volatiles burnout; and 2) solid residue (char) burnout. Duration of step 2 in pulverized coal-fired boilers takes 90%+ of total burnout time. Therefore, under kinetic conditions of Zone II the role of heterogeneous reactions even further increases due to the intentional delay of the combustion


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processes taking place in sub-stoichiometric combustion (burner) zone and then in an offset downstream over-fire air ports (OFAP) zone where a balance of combustion air is supplied.

Often, the perception of engineers is that coal combustion involves two heterogeneous reactions (R1, R2) and two/three homogeneous reactions (R3, R4, R4a).

+ = , ( 1) + 12 = 2 , ( 2)

+ 12 = , ( 3) + ↔ + , ( 4) + 1

2 ↔ , ( 4 )

These reactions dominate combustion in kinetic Zone III (see Figure 2a). For Low NOx combustion in Zone II, two additional heterogeneous reactions (R5, R6) [15] are significant even for oxygen-enriched oxidizers [7]. Only when accounting for these reaction rates the higher apparent rates of coal/char reactions under kinetic conditions in Zone II could be explained.

+ = 2 , ( 5) + = + , ( 6)

Experience and analyses have shown that homogeneous “water-shift” reaction (R7) is important in Zone II [15]. + = + , ( 7)

The authors of this article also suggest to include a reforming reaction for hydrocarbons present in volatile matter (R8), since it was proven important in combustion and NOx formation of other gaseous hydrocarbon fuels, e.g. steam injection for natural gas combustion (burners/gas turbines).

+ = + ( + 2) 2⁄ , ( 8)

The thermal effects of outlined above global reactions making major impact on combustion in Zone II are shown in Table 3. Note, these thermal effects are in reference to the standard conditions. Effect on thermal effects under operating conditions is discussed below.

The study and analysis of internal particle surface have shown that

its reactivity changes from point to point. Some points exhibit irregularities in chemical and crystalline structure (geometrical arrangement of carbon corner atoms, inorganic substance inclusions, presence of oxygen or hydrogen groups). These points generate different molecular forces (adsorption/desorption) that differentiate reactivity of one part of the surface from another. The points of higher reactivity are called “active centers” or “active sites”. As mentioned above, these centers are responsible for acceleration (catalytic effect) of reactions taking place on such active centers, reducing activation energies of reaction by approximately 50%. Total number of active centers at any time can be represented by a sum of free [Cf] and occupied [C(O)] centers.

DH, DH, Btu/lb-mol kJ/kmol

R1 -1.69E+05 -3.94E+05 Exothermic, Heterogeneous

R2 -4.73E+04 -1.10E+05 Exothermic, HeterogeneousR3 -1.22E+05 -2.84E+05 Exothermic, Homogeneous

R4 (as CH4) -3.48E+05 -8.10E+05 Exothermic, Homogeneous

R5 7.42E+04 1.73E+05 Endothermic, HeterogeneousR6 5.65E+04 1.31E+05 Endothermic, HeterogeneousR7 -1.77E+04 -4.12E+04 Exothermic, Homogeneous

R8 (as CH4) 8.86E+04 2.06E+05 Endothermic, Homogeneous

Reaction Number

Type

Table 3. Thermal Effect of Reaction at 14.696 psia, 77oF (0.101 MPa, 298 K)


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[ ] = [ ] + [ ( )], ( . 1)

The number of active centers is changing during reaction and could be either destroyed, occupied or restored. The status of centers could be altered in some control way through thermochemical processes whereas number of active centers depends on particle temperature, rate of heating, and composition of bulk gases surrounding particles [9, 13, 14]. Consequently, the reactivity of a coal particle could be corrected in more precise way to improve process outputs by maintaining presence and conditions of such active centers.

A dominant source of NOx emissions in modern Low-NOx coal-fired systems is fuel-bound nitrogen or (fuel-N), which is responsible for 70% to 80%+ of NOx formation. Depending on boiler furnace temperature and availability of oxygen NOx also can be formed by thermal dissociation of N2 and O2 atoms in oxidizer (i.e. thermal NOx). Due to their nature, thermal NOx could be more or less significant as soon as local flame temperatures exceeding 2400oF (~1300oC). Thermal NOx may contribute 10% to 30% under Low-NOX combustion. Besides the fuel-bound nitrogen and the thermal NOx, a prompt NOx could be generated during initial stages of fuel decomposition, when high energy hydrocarbon radicals are braking N2 and O2 atoms, thus causing nitrogen oxidation at low temperatures [16]. Prompt NOx in case of coal combustion may reach ~5% of total nitrogen oxides emitted by flame.

It is a common understanding that the main path of fuel-N conversion to NOx could be presented by the following, yet simplified, scheme [18]:

− ⇛ ⇛ ⇛ ⇛ ⇛⇛ (E1)

HCN (hydrogen cyanide) is a main precursor of NOx formation. The rate of HCN/NHi formation/distraction appears to be directly related to coal rank [18]. For low rank coals the level of HCN/NHi is the highest, whereas bituminous and Low-Volatile coal generates less HCN/NHi than preceding ones in an order of mentioning. As already discussed above NOx emissions vs. ranks of coals are precisely in a reverse order, i.e. less NOx is generated by low rank coals [19]. Such relationship is in agreement with the findings of practice and science. It reinforces existing understanding of the internal particle surface role on NOx emissions release: coals with higher internal coal particles surface generate less NOx (See above).

The multi-path of fuel-N conversion to NOx in utility boilers as proposed S.Gil [18] is presented in Figure 3. Following coal pyrolysis, fuel-N in VM is released into a boundary layer where an atomic nitrogen N may undergo either oxidation to NO/N2O or recombines into a stable molecular N2. Even though the reactions are homogeneous the presence of char surface plays important catalytic role (see below). Char-N undergoes similar reactions heterogeneously where bound nitrogen reacts with the active centers of the particles. Here it has to be underscored that number of free active centers measured in chars obtained by short time exposure (fraction of a second) to a rapid heating and pyrolysis was the highest [13]. Both gasification [20] and Low-NOx practices [21] also suggest that higher rates of fuel-N conversion to stable N2 occur when coal is subjected to pyrolysis at higher temperatures. These independent results point-out that widely accepted reaction of catalytic NOx reduction


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(R11) is one of the major mechanism that minimizing fuel-N conversion to NO in heterogeneous reactions. Above burner zone nitrogen oxides NOx and N2O undergo homo- and heterogeneous reduction with the residual char while adsorption and desorption of the bulk gas under reduced oxygen availability continues to support reduction of NOx to molecular nitrogen N2. There is no consensus between scientists on the contribution of volatile nitrogen and char-N to a total NOx emissions. In laboratory controlled experiments it was found that volatile-N and

char-N produce approximately equal shares of NOx [6,19]. For the conditions of utility boilers [18] analysis of numerous independent studies suggested that share of VM and char bound nitrogen varies, and depends on temperature and specifics of combustion system design. This conclusion is in agreement with experiment work [14] that confirms significant variation in a number of available active centers depending on the rate of coal particles heating during pyrolysis.

There are numerous models [6,7,11,17,18] that include series of reactions describing fuel-N conversion. Analysis of these models is not an intent of this paper. Here we concentrate only a few common ones, widely accepted heterogeneous reactions [18.19] that are catalytic in nature and will help to explain the mechanism behind the technology presented hereafter:

+ 12 + , ( 9) 2 + → + [ ( )] , (R10)

[ ( )] → + ( 11)

As above equations show, presence of CO is essential for NOx reduction providing that internal particle surface through burn-out and kinetic conditions surrounding particles allow to maintain activity of the surface. It could be also concluded that should an internal char surface increase due to changes in the bulk gas parameters and composition it would move the balance of fuel-N conversion toward production of stable N2.

Summarizing the discussion in this section the following major points must be reiterated:

1. Under Low-NOx combustion the kinetic regime has shifted to Zone II (See Figure 2). 2. In Zone II coal oxidation reactions by CO2 and H2O are very important, especially under

fuel rich conditions. These reactions with char surface provide chemical cooling, maintain char structure and prevent char surface ablation at high temperatures.

3. Active internal particle surface is greater than it’s external by ~ 6 orders of magnitude and accelerates coal burnout under lower temperature conditions.

4. Under pyrolysis conditions (Zone II) the internal particle surface grows up to 2.5 times depending on rank and bulk gas composition until 50% to 60% of particle mass burn-out.


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5. Char surface due to the presence of active centers serves as a catalyst for chemical reactions; Practice confirmed that internal coal char surfaces with higher share of active centers has a strong influence on NOx reduction.

6. Activation energies of chemical reactions on active char centers can be reduced by 50%.

4. Modified Coal Combustion Process and In-Furnace NOx Reduction

As follows from above review of coal kinetics further improvement of in-furnace NOx formation should have a means to modify kinetics in a way that allows increasing coal/char particles porosity throughout staged combustion under fuel rich conditions, improve char conversion to gaseous reactants CO/H2 and enhance its reactivity, (i.e. number of active centers) that results in both NOX and unburned carbon reduction.

This idea of controlling porosity and catalytic properties of the char is not new. For centuries activated char was produced by subjecting coal to high temperature combustion products (pyrolysis) whereas steam was added to increase activated char porosity measured in thousands square meter per gram (i.e. m2/g based on CO2 sorption). Re-activation of used char also performed in the high temperature flue gases mixed with steam.

Development of the gasification process early in the 1960s in the USA demonstrated significant increase in syngas (CO+H2) yield and minimization of residual char (UBC/CIA) by about 60% after addition of steam to the process [22]. Later during development of Integrated Gasification Combined Cycle the effect of steam on syngas combustion was attributed to its effect on HCN (NOx precursor, See above) reduction due to presence of hydroxyl group OH reaction [22, 23]. A “scavenging effect” of steam on HCN was also reported by many experimental studies along with reduction of thermal and prompt NOx. The latter, is well known fact; steam injection was accepted by DOE as one of method of nitrogen emissions control in natural gas and oil combustion applications. As mentioned above, thermal NOx may contribute 10% to 30% during coal combustion.

Experimental studies [23,24] of steam effect (i.e. CO2 and H2O gasification) indicated a critical role of each component on internal particles surface development. Water vapor due to the smaller size of its molecules and higher diffusion coefficient has a much greater ability to penetrate into small pores of internal surface (micro-pores). As the result of its higher “mobility” and lesser energy required by reaction of char with water vapor (See above - Table 3, R6) micro-pores grow to meso-pores thus allowing larger CO2 molecules to penetrate and react by (R5) deeper inside the particles (See Figure 2a, and Table 3).

Steam was also successfully used in new technology - fuel cell utilizing coal [26]. Steam was introduced into process to improve coal conversion to hydrogen by reactions (R6) and (R7), and thus improving (3 folds) efficiency of coal utilization in fuel cells [26].

At this time practically the only coal application that have not benefited from the use of steam for more efficient coal utilization is the utility sector.


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VESI has researched steam injection for steam power cycles for fossil fuels, and developed solutions that concurrently improve efficiency and reduce NOx emissions. All aspects of technologies were analyzed – kinetics, heat transfer in boilers, steam cycle material and energy balances, cost analysis and process economics, and major constrains. A few US patents received by VESI that cover these solutions; US Patents 7,690,201, 8,453,452 are for steam cycle in particular. The NOx reduction portion of VESI’s solution (NOx module – E-NOx) is the first of two add-on modules that collectively provide substantial increase in plant thermal efficiency and NOx reduction. The combined effect of two modules is greater than the sum of their individual effects. In this article the NOx reduction module is presented. It delivers major contribution to NOx reduction and sizable efficiency improvement, especially for supercritical boilers.

A simplified diagram in Figure 4 depicts one possible way of E-NOx system integration into a steam cycle power plant. Here, a single-reheat, super-critical plant consisting of an opposed-fired steam generator equipped with OFA ports is shown along with the steam turbine with high, intermediate, and low pressure sections and feed water heaters.

To maximize work produced by a turbine, the steam extractions for NOx control are distributed. A portion of high pressure steam is taken from HP section of turbine and low pressure steam is taken from LP section (lines 1 and 2

respectively). A steam compressor 3 uses high pressure steam 1 as a motive medium to pressurize steam from line 2 and discharges a mixed steam flow at intermediate pressure into a steam piping system for distribution into the boiler furnace or burners (injection through burners is preferred). The piping system design is similar to a soot-blowing piping system, with the exception of flow control valves, which proportions steam flow to a group of burners by boiler elevations. The control of Steam-to-Coal ratio and secondary air bias provide flexibility to optimize in-furnace NOx and UBC reduction. Additional improvements to the process and enhancement in energy saving is provided by the make-up water preheat by a flue gas leaving the boiler and in a reheater 4 downstream of the steam compressor 3.

The direct injection system as shown in Figure 4 is an open system. It requires larger than typical make-up water supply. Should high quality feedwater use for NOx control be viewed as a commercial constrain, VESI offers an indirect steam injection system that does not require high quality polished feedwater. A much lower quality (e.g. service water) could be used for NOx control.

Since use of steam for injection affects overall operation of the steam cycle it requires to assess different aspects of boiler and cycle performance.

Figure 4. E-NOx integration with Steam cycle for in-furnace NOx reduction: Direct injection arrangement

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The brief review and analysis of these aspects are provided below.

Boiler Efficiency. There is a perception of some performance engineers that adding steam to the combustion would result in decrease of boiler efficiency due to losses with wet flue gas. In this regard reference to ASME code for boiler performance, PTC 4 is helpful (2008 or later edition). There are four major energy categories in the code: fuel input (QrF), credits (QpB), energy

outputs (QrO) and losses (QpL). Fuel efficiencies can be determined by two methods: a) Input-Output Method, and b) Heat Loss Method, as expressed below:

100100100

InputFuel

CreditsLosses

InputFuel

OutputEfficiency fuel , (1)

or QrFQpBQrFQpLQrFQrOfEf f //100)/(100 , (1a)

Among several credits considered there are two of importance to us: a) “energy supplied by additional moisture” (e.g. steam for liquid fuel atomization), and b) “moisture in entering air”. As (1a) shows these sources (credits) do not contribute to the losses associated with wet flue gas, and therefore do not affect boiler losses. Indeed, any moisture that enters boiler in the form of steam does not consume fuel energy for vaporization. Therefore, in accord with Heat-Loss Method the moisture losses at a boiler exit shall be corrected by amount of the latent heat introduced at a boiler input. Moreover, if steam enters the boiler in a superheated state then available heat or sensible heat in the input increases. For example, for boiler firing bituminous coal (HHV=11,000

Btu/lb) with 0.4 pounds of steam supplied at 800oF and 50 psia (h=1,432 Btu/lb) and flue gas leaving boiler at 300oF (h=1,192,7 Btu/lb) the heat input increase is equivalent to 0.87% per each pound of coal. Another saving comes due to reduction of unburned fuel losses (UBC/CIA). From gasification experience we already learned that addition of steam considerably reduces residual char. CFD modeling by an independent company have shown that introduction of steam for NOx control in Tangentially-fired boiler lead to 60% - 90% CIA reduction at moderate steam injection rates (Figure 5). Considering an average, losses

in power sector due to UBC(CIA) are on the order of 0.4% to 1.0%, the equivalent fuel saving with steam injection will range between 0.2% to 0.9% of fuel input.

Gathering from above one now can conclude that addition of superheated steam to coal combustion will lead to 1% to 2% of heat input increase per unit of fuel burnt. This energy will result in extra steam generation and, in turn, to higher power output generated per pound of fuel burnt.

Heat Transfer. Furnace water wall slagging under sub-stoichiometric Low-NOx combustion conditions often leads to firing rate increase (fuel losses). Steam wall blowers are one typical

Figure 5. Predicted CIA: Parametric case 1 is the only one without steam injection.


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method that provides effective resolution to furnace slagging. Sootblowers are also the most common equipment for fouling control of heat recovery surfaces in coal-fired boilers.

CFD modeling by an independent company confirmed the expected trend in furnace slagging. The results for moderate rates of steam injection (Figure 6) indicate about 30% reduction in furnace slagging intensity to be expected,

Several years of coal-fired utility units’ study [27] suggested that reduced furnace slagging leads to additional fuel saving and about ~10% NOx reduction. The later can be attributed to a reduced contribution of the thermal NOx

indicated by a lower furnace exit gas exit temperature (FEGT) at reduced furnace slagging.

In Table 3 above the main reactions in kinetic Zone II – (R6), (R7), (R8) are endothermic. There were some inquiries concerning their impact on furnace temperature and on heat transfer. It must be underscored that the thermal effect of (R6), (R7), (R8) depends on operating temperature at which reactants enter the process. According to Hess’s law of thermodynamic the standard effect of reactions is determined by a difference of standard energies of formation for substances present in products and reactants of a reaction are expressed in reference to standard conditions (14.696 psia and 77oF):

= ∑ ∆ ( ) ∑ ∆ ( , (2)

For reactants participating in reaction (i=1, 2,…k) at temperatures other than standard, thermal effect of same reaction is changing and is determined by Kirchhoff’s law of thermodynamic that in terms of Hess’s law could be written as

( ) = + ∑ ∆ ( ), (2a)

Depending on value of the sum in (Eq 2a) the thermal effect of reactions tabulated in Table 3 would change accordingly.

Kirchhoff’s law is used in our daily practices; firing a fuel with combustion air temperature at 77oF vs. combustion air temperature greater than 77 oF results in greater energy released in the furnace, i.e. greater thermal effect vs. one calculated at standard conditions. This example is for exothermic reaction. The same is true for endothermic reactions (R6), (R7), (R8), where any excess of energy above standard conditions will reduce negative thermal effects indicated in Table 3. In other words, energy used for preheating of reactants will minimize energy requirement to generate the products. Therefore, submitting products of (R6), (R7), (R8) for combustion by reactions (R3) and (R4a)

Figure 6. Reduced furnace slagging with (Module 1) and without steam injection (Base Line)


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will resulting in greater thermal effects than those indicated in Table 3, i.e. thanks to reduction in energy of formation of the reactants CO and H2.

The effects explained above known to industry as thermochemical recuperation and is presently utilized in gas turbines and natural gas-steam reforming processes. Similar processes and equipment were also promoted across the world for various applications due to more effective waste heat energy utilization, e.g. comparing to air preheater.

It should be noted that the thermal effect of reactions also depends on the presence of catalyst. In studies referenced above a substantial about, 50% reduction, of the activation energy on char surface is observed. Consequently, the energy of formation in Table 3 would be affected in addition to thermal effect or reactant preheat explained above. VESI did not evaluated potential impact of char catalytic properties on rates of CO and H2 formation, but expects that such catalytic effects would be important for the overall process effect on NOx and efficiency. The effects will be site-specific depending on composition coals, and mineral matter in particular.

Gathering from above facts no significant changes in furnace temperature profile were expected under steam injection conditions specified for NOx reduction process. Results of CFD modeling in Figure 7 showed that under preferred operating conditions (other than Case-1_VESI) gas temperature may be lower by about 50oF at some elevations or may even exceed operating temperature without steam injection (Parametric Case 1).

Emissivity of flue gas gases is determined by partial pressure of tri-atomic gases (CO2, SO2 and H2O) and by ash/char particles. VESI used radiant heat calculations adopted by OEM companies for boiler design [28]. This methodology accounts for furnace slagging, location of flame ball in the furnace, partial pressure of individual triatomic gases, radiation bands/spectra overlap, furnace size and mass-average size of fuel particulates based on grinding practices. This methodology was verified in utility boilers for many decades.

Figure 8 shows incident heat flux emitted by products of bituminous coal combustion with and without steam injection. For both cases the boiler water walls assumed to have same slag accumulation. As the results show the same heat flux can be achieved by the flue gas produced with and without steam injection as soon as the

Fig 7. Gas temperatures by furnace elevation

Figure 8. Steam injection effect on radiant heat flux


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temperature difference of bulk gases with steam injection would not fall below 50oF (30K) at lower temperature and 100oF (60K) – for high temperatures.

Some important details yet to be underscored here; data in Figure 8 is derived for the same operating conditions at the excess air for cases with and without steam injection. Considering significant improvement in UBC under steam injection conditions the excess air could be reduced thus leading to increase of the bulk flue gas temperatures, and therefore incident heat flux. Also under steam injection condition a burner zone stoichiometry increases compared to Ultra-Low-NOx operation to achieve superior NOx reduction. As known practice suggests under such conditions, less slagging would occur when burning the same coal leading to further reduction of fuel consumption and overall cycle efficiency increase.

Convection heat transfer coefficient also increases with moisture content [20]. Increase in heat transfer coefficient and greater energy and mass of the flue gas flowing through the boiler will compensate some reduction in flue gas temperatures. A lesser degree of a boiler heat recovery area fouling in case of steam injection is expected, as follows from experience and directions of the soot blower manufacturers.

Thus, under steam injection conditions as required by the E-NOx performance, slightly lower flue gas temperature will not result in reduced heat transfer. It will be compensated by improvement in heat transfer rates due to reduced slagging conditions, lower excess air, and higher burner zone stoichiometry.

5. Evaluation of E-NOx Performance and Economic benefits.

The evaluation of the E-NOx performance was done by a third party using CFD analysis and by kinetics modeling using Langmuir–Hinshelwood equations [9,18]. The latter method has been successfully applied to and explains the reaction rates for coal combustion in kinetic Zone II[17,19]. Based on these studies it was concluded that applying described E-NOx technology will result in

concurrent reduction of NOx, CO and fuel loss (UBC). There effect depends on fuel rank and combustion system arrangement, steam parameters and steam injection. The expected concurrent reductions of NOx and associated components presently limiting in-furnace NOx control are

summarized in the Table 4.

The effect on coals with lower VM, i.e. smaller internal surface and inherent moisture will benefit the most.

The CFD analysis has confirmed that E-NOx will bring nitrogen oxides out of the furnace to the level typically achieved with the help of SCR. As mentioned above the concurrent effects include: increase in furnace stoichiometry, reduced UBC (CIA) and reduced slagging (See Figure 5 and Figure 6).

Table 4 . Expected E-NOx Performance

Species Reduction %

Low VM Mid VM High VM NOx ~50 40-25 15-25

UBC(fuel loss) 50-60 60-80 70-90

CO 50+ ~40 10-25


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As it was already discussed above, the injection of steam for NOx control provides additional heat input. Therefore, the steam generator will produce more steam at the same fuel input in the proportion to energy of the injected steam which is recovered from the flue gas and regenerative heaters as shown in Figure 4. Thanks to larger steam throughput through the steam turbine the electrical output will increase for the same fuel firing rate, i.e. the cycle efficiency increases.

Several studies where performed for subcritical units that indicated the increase in boiler efficiency by 1.5% to 2.5% depending on fuel fired, steam plant and combustion system arrangement, and E-NOx configuration applied to specific case. This results in overall cycle efficiency improvement on the order of 1% or more. For supercritical units the increase in efficiency is greater and relates to larger share of work performed by HP turbines in the supercritical vs. subcritical cycle.

Table 5. Economic Evaluation of E-NOx and BACT Options

This increase in thermodynamic efficiency provides quick return on investment due to reduction in fuel consumption, and if used alone will allow to meet regulations for NOx emissions and avoid significant capital cost associated with available BACT technologies.

E-NOx can also be used together with SCR. In this case it will allow to compensate efficiency losses associate with the technology (see Table 1) and in addition significantly cut back on variable cost of reducing reactant. Other benefits and improvements deemed feasible in regard to catalyst management programs and extension of catalyst life. The latter benefits were not accounted for in the estimated payback time shown in Table 5.

7. Conclusions

E-NOx overcomes limitations of Ultra-Low-NOx by controlling internal char surface size and its chemical activity through burnout process.

E-NOx makes possible further substantial reduction of NOx by primary means (In-Furnace).

Retrofit - 600 MWe (Net) PC-fired boiler Sub-Critical , Low Sulfur Bituminous Coal

Base SCR SNCR E-NOx

Only

Existing SCR + E-NOx

Normalized Cost of Technology, $/kW NA $ 250 $ 21 $ 5 $ 5

Retrofit Cost,M$US $ 150.0 $ 12.6 $ 2.0 $ 2.0

Net Heat Rate(MCR), Btu/kW (HHV) 9,610 9,760 9,830 9,340 9,470

Plant Efficiency, % 35.0 34.5 34.2 36.0 35.5

NOx in Furnace, Lbs/MMBtu 0.25 0.25 0.25 0.08 0.08

NOx In Stack, Lbs/MMBtu 0.25 0.05 0.15 0.08 0.05

- Fuel Cost (Loss)/Savings, M$US*) Base Line ($1.2) ($1.7) $2.1 $1.1

- Variable NOx Control Costs, M$US/yr Base Line ($1.150) ($2.67) ($0.350) ($0.81)

- Fixed O&M (NOx related), M$US/yr Base Line ($0.5) ($0.2) ($0.14) ($0.64)

Total O&M Cost Change (Loss) /(Saving) M$US/yr Base Line ($2.8) ($4.6) $1.6 ($0.4)

Same vs. SCR , M$US/yr Base Line ($1.8) $4.5 2.5$

Pay Back vs. Base, month Base Line Never Never 15 mo NA

Pay Back (Base + SCR), month Base Line NA NA 10 mo


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Technical approach behind E-NOx was used for decades in other energy sectors and now in Fuel Cells.

E-NOx utilizes equipment that has been used in Power plants since the 1800s.

Proper integration of E-NOx into steam plant reduced NOx, allows for fuel savings through improved thermal efficiency, lowering LOI, and minimizing slagging

E-NOx if used alone will generate operational profit

E-NOx with SCR will cut >80% of SCR Operating costs

References:

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2. Capital Investments in Emission Control Retrofits in the U.S. Coal-fired Generating Fleet through the Years – 2016 Update. Thomas Hewson, Phillip Graeter. Report of Energy Ventures Analysis, Inc. (Source EIA 767/860 forms)

3. Bin Xu, David Wilson, and Rob Broglio. Lower-Cost Alternative De-NOx Solutions for Coal-Fired Power Plants, POWER ENGINEERING, 12/21/2015

4. I.W. Smith. The combustion Rates of Coal Chars: A Review. 9th International Symposium on Combustion/The Combustion Institute, 1982, pp. 1045-1065

5. D.G.Roberts, D.J.Harris. Akinetic Analysis of Coal Char Gasification Reactions at High Pressures. Energy and Fuels, 2006,20, pp. 2314 -2320

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7. M.Geier, et al. On the Use of Single-Film Models to Describe the Oxi-fuel Combustion. Applied Energy, 93,(2012) 675-679

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9. S.Gil, P.Mocek, W.Bialik. Changes in Total Active Centers on Particles Surfaces during Coal Pyrolysis, Gasification, and Combustion. Chemical and Process Engineering 2011, 32(2), pp 155-169

10. J.Thomas, Jr., H.Damberger. Internal Surface Area, Moisture Content, and Porosity of Illinois Coals. State Geological Survey, CIRCULAR 493, 1976

11. J.F.Unsworth, D.J.Barratt, P.T.Roberts. Coal Quality and Combustion Performance. Coal Science and Technology, Vol. 19. Elsevier/Shell Research, 1991

12. T.Gale. Effect of Pyrolysis Condition on Coal Char Structure (Thesis), Brigham Young University, 1994


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13. T.Gale, C.Bartholomew, T.Fletcher. “Decrease in Swelling and Porosity of Bituminous Coals during Devolatilization at High Heating Rates. 25th Symposium (International) on Combustion, Irvine, California, 1994

14. L.Radovic, et/al. Importance of Active Sites in Coal Char and Carbon Gasification, PSU, library, https://web.anl.gov/PCS/acsfuel/preprint%20archive/Files/Volumes/Vol28-1.pdf

15. J.Tomaczek, Coal Combustion. Krieger Publishing Co, Malabar, Fl.1994.

16. EPA Technical Bulletin, Nitrogen Oxides. EPA-456/F-99-006R, 11/1999

17. A.Molina, E.G.Eddings, D.W.Pershing, A.F.Sarofim. Char Nitrogen Conversion: Implications to Emissions from Coal Fired Utility Boilers. Progress in Energy and Combustion Science 26 (2000) 507–531

18. S.Gil. Fuel-N Conversion to NO, N2O, and N2 during Coal Combustion. Fossil Fuel And Environment Chemical and Process Engineering 2011, 32(2), pp 155-169

19. A.Molina. Nitric Oxides Destruction During Coal and Char Oxidation Under Pulverized Coal Combustion Conditions. Combustion and Flame, 136 (2004)303 – 312.

20. Steam Its Generation and Use. Babcock &Wilcox. 40th edition, 1992.

21. Mitsubishi-Hitachi Low NOx Burners. https://www.mhps.com/en/products/detail/low_nox_burner.html

22. D.E.Giles, et al. NOx Emission Characteristics of Counter Flow Syngas Diffusion Flames with Air Stream Dilution. Fuel, 85, 2006, 1729 – 1742

23. J. Ratafia-Brown, L. Manfredo, J. Hoffmann, M. Ramezan “Major Environmental Aspects of Gasification-Based Power Generation Technologies” U.S. Department of Energy, Office of Fossil Energy, National Energy Technology Laboratory, December 2002

24. E.F. Aul et al. In-Process Control of Nitrogen and Sulfur in Entrained bed Gasifier. EPA Project Summary. EPA/600/S7-86/051 Mar. 1987

25. T.K.Gale. Effect of Pyrolysis conditions on Char Properties. Brigham Young University. Theses. 1994

26. Steam - Cleaning Coal. Mechanical Engineering, June 2016, p.19.

27. E.Levy, T.Elderdge. I&C Enhancement for Low NOx Boiler Operation. Energy Research Center, Lehigh University

28. A.G. Blokh, R.Viscanta. Heat Transfer in Steam Boiler Furnaces. Taylor & Francis, 1988

29. Xiang Gou, et al. Effect of Water Vapor on Pyrolysis Products of Pulverized Coal. Procedia Environmental Sciences 12 (2012) 400-407

Documents

CoalGen Paper Manuscript(1) Modified Coal Combustion Reduces NOX and Fuel Consumption