Question 1

By-products of high-temperature coal carbonisation: Which of the following is not recovered as a by-product from a conventional high-temperature coke-oven plant?

Accepted Answer

Introduction / Context:High-temperature coal carbonisation (around 1000–1100°C) yields metallurgical coke, coke-oven gas, tar, and liquor. From these, by-product plants recover valuable chemicals. Recognizing which products are typically recovered guides economic evaluation and environmental compliance.Given Data / Assumptions:Coke-oven gas contains H2, CH4, CO, CO2, small higher hydrocarbons, NH3, H2S, and light aromatics (“benzol”).Coal tar is distilled to naphthalene, creosote oil, pitch, etc.Ethylene is negligible in conventional coke-oven gas and is not a standard recovered by-product in these plants.Concept / Approach:Standard by-product recovery includes benzol by absorption from gas, ammoniacal liquor from gas scrubbing, naphthalene from tar/gas, and pitch/creosote from tar distillation. Ethylene is not typically recovered; it is a core product of steam cracking of naphtha/ethane, not coal carbonisation.Step-by-Step Solution:List typical by-products: benzol, ammonium sulphate (from NH3), tar distillates (naphthalene, creosote), pitch.Check ethylene: not a conventional product; not economically recovered in coke-oven operations.Therefore select “Ethylene” as the exception.Verification / Alternative check:Block flow diagrams for coke plants confirm benzol recovery trains, ammonia recovery, tar distillation, but no ethylene separation units.Why Other Options Are Wrong:Benzol, PCM, naphthalene, and ammoniacal liquor are well-established by-products in integrated coke-oven by-product recovery schemes.Common Pitfalls:Assuming all hydrocarbon gases include recoverable ethylene; conflating petrochemical steam-cracking with carbonisation.Final Answer:Ethylene

Question 2

Combustion classification: The overall chemical reaction of fuel combustion is best described as which type of thermal process?

Accepted Answer

Introduction / Context:Combustion is a rapid oxidation of fuels releasing heat and, often, light. Recognizing that combustion is exothermic underpins furnace design, flame temperature estimates, and energy balance calculations for boilers, engines, and gas turbines.Given Data / Assumptions:Complete combustion to CO2 and H2O is considered.Standard conditions for heats of reaction unless otherwise specified.Side phenomena (e.g., ignition kinetics) do not change the overall enthalpy sign.Concept / Approach:The standard heats of formation of CO2 and H2O are much lower (more negative enthalpies) than those of typical fuels. Thus, the enthalpy change of combustion, ΔH_comb, is negative, meaning heat is released to the surroundings. While chain-branching kinetics can involve radical steps, the net process is exothermic.Step-by-Step Solution:Write a representative reaction: CH4 + 2 O2 → CO2 + 2 H2O + heat.Compute ΔH from heats of formation: ΔH ≈ [Σ nΔHf(products)] − [Σ nΔHf(reactants)] → negative.Conclude the overall process is exothermic.Verification / Alternative check:Adiabatic flame temperature calculations show temperature rise, which is consistent with exothermic heat release supplying sensible heating to products.Why Other Options Are Wrong:Endothermic would require heat input; auto-catalytic describes kinetics but not heat effect; “neither” contradicts calorimetry; “thermally neutral” is not applicable for hydrocarbon combustion.Common Pitfalls:Confusing local endothermic steps (e.g., fuel cracking) with the net reaction; overlooking incomplete combustion or dissociation while assessing overall heat effects.Final Answer:Exothermic

Question 3

Improving solid-fuel combustion efficiency: Which practice will not help achieve higher overall efficiency in firing solid fuels?

Accepted Answer

Introduction / Context:Combustion efficiency reflects how much of the fuel’s chemical energy is converted into useful heat. In boilers and furnaces burning solid fuels, operational choices strongly influence stack losses, unburned carbon losses, and radiation/convection losses. Identifying counterproductive practices helps avoid energy waste.Given Data / Assumptions:Standard solid-fuel firing in boilers/furnaces.Efficiency losses include flue-gas sensible heat, incomplete combustion, and moisture/ash effects.Heat-recovery equipment (economizers, air preheaters) is available.Concept / Approach:High flue-gas exit temperature means more sensible heat leaves the stack unrecovered, reducing efficiency. Conversely, optimizing particle size/moisture, employing efficient burners or stokers, and maintaining proper excess air improve mixing, burnout, and heat transfer—thus increasing efficiency. Lowering the stack temperature within dew point limitations is desirable.Step-by-Step Solution:Identify major loss: stack loss ∝ m_dot_gas * Cp_gas * (T_stack − T_ambient).Thus, “keeping T_stack very high” raises losses and hurts efficiency.Proper air control and firing method reduce unburned carbon and CO formation; fuel prep improves burnout and heat release uniformity.Verification / Alternative check:Boiler efficiency audits show strong sensitivity to exit-gas temperature; adding economizers/air preheaters lowers T_stack and recovers heat, demonstrating improved efficiency.Why Other Options Are Wrong:Fuel preparation, correct air supply, efficient firing, and heat recovery all contribute positively to efficiency by reducing losses and improving combustion completeness.Common Pitfalls:Reducing stack temperature below acid dew point can cause corrosion; air control should avoid both deficiency (CO/unburned) and excess (excess air loss). Balance is key.Final Answer:Keeping the flue-gas exhaust temperature very high

Question 4

Coal gasification chemistry: At higher gasification temperatures, which product distribution is favored in the equilibrium between CO2 and CO in the presence of steam and carbon?

Accepted Answer

Introduction / Context:In coal gasification, reactions such as the Boudouard reaction (C + CO2 ⇌ 2 CO) and the water–gas reaction (C + H2O ⇌ CO + H2) govern the CO/CO2 balance. Temperature strongly shifts these equilibria. Understanding the temperature dependence helps control syngas composition for downstream uses (e.g., Fischer–Tropsch, power generation).Given Data / Assumptions:Key equilibria: C + CO2 ⇌ 2 CO; C + H2O ⇌ CO + H2.Operating at elevated temperatures typical of entrained-flow or fixed-bed gasifiers.Equilibrium trends considered; real systems also involve kinetics and transport.Concept / Approach:The Boudouard reaction is endothermic in the forward direction (forming CO). According to Le Châtelier’s principle and equilibrium thermodynamics, raising temperature favors the endothermic direction, increasing CO at the expense of CO2. Similarly, the steam–carbon (water–gas) reaction is endothermic; higher temperature drives it forward to produce more CO and H2.Step-by-Step Solution:Consider C + CO2 ⇌ 2 CO: ΔH > 0 forward → high T favors CO.Consider C + H2O ⇌ CO + H2: ΔH > 0 forward → high T favors CO + H2.Therefore, high temperature implies more CO and less CO2.Verification / Alternative check:Equilibrium constant K increases with T for endothermic reactions (d ln K / dT ∝ ΔH/R). Reported equilibrium charts show CO fractions rising with temperature, consistent with practice.Why Other Options Are Wrong:“High CO2” contradicts endothermic equilibria trends. “Neither affected” is false; temperature is a key lever. Selecting both “low CO2” and “high CO” correctly captures the shift.Common Pitfalls:Ignoring the effects of steam-to-carbon ratio and pressure; overlooking water–gas shift (CO + H2O ⇌ CO2 + H2) which can alter CO/CO2 downstream at lower temperatures with catalysts.Final Answer:Both (b) and (c)

Question 5

Explosives precursors: The aromatic chemical predominantly used to manufacture TNT (2,4,6-trinitrotoluene) is

Accepted Answer

Introduction / Context:TNT is a classic high explosive produced by nitration of an aromatic hydrocarbon. Recognizing its precursor is important in petrochemical feedstock management, safety, and regulatory control. While several aromatics occur in coal by-products and petroleum streams, only specific structures yield TNT efficiently.Given Data / Assumptions:TNT stands for 2,4,6-trinitrotoluene.Nitration adds nitro groups to an aromatic ring under controlled conditions.Feedstock purity and substitution pattern direct the nitration pathway and yield.Concept / Approach:The name “trinitrotoluene” indicates that the parent aromatic is toluene (methylbenzene). Sequential nitration yields mono-, di-, and finally trinitro derivatives predominantly at 2,4,6 positions due to the methyl group’s directing effects under mixed-acid conditions. Benzol is a mixture of light aromatics, not a single compound; pyridine is a heteroaromatic (not nitrated to TNT), and creosote is a tar distillate mixture. Xylenes are dimethylbenzenes and nitration of xylene gives nitroxylene isomers, not TNT.Step-by-Step Solution:Identify the parent hydrocarbon from the product name: trinitro + toluene → toluene.Exclude non-matching aromatics and mixtures.Select toluene as the correct precursor.Verification / Alternative check:Process descriptions of TNT manufacture consistently start from toluene feed, mixed-acid nitration, and subsequent purification/stabilization steps.Why Other Options Are Wrong:Benzol is a mixture; pyridine’s ring chemistry is different; creosote is a complex oil fraction; xylene would form nitroxylenes, not TNT.Common Pitfalls:Confusing “benzol” with benzene; overlooking how substituents direct nitration positions on aromatic rings.Final Answer:Toluene

Question 6

Coking propensity tests: The Gray–King Assay and the Free Swelling Index (FSI) of a coal primarily measure its

Accepted Answer

Introduction / Context:For metallurgical coke production, a coal’s ability to soften, swell, and re-solidify into a coherent porous mass (coke) is critical. Laboratory indices help screen coals for coking blends. Two common tests are the Gray–King Assay and the Free Swelling Index (FSI), both of which relate to caking or agglutinating behavior under heating.Given Data / Assumptions:Gray–King Assay grades the type of coke formed by heating a standard coal charge in a silica tube under specified conditions.FSI (also called Swelling Index) measures the volume increase of a coal button upon heating under prescribed conditions.Both tests correlate with coking potential in blends.Concept / Approach:While “swelling” is observed, these tests are not merely about expansion; they indicate whether plasticity develops and particles fuse (agglutinate) into a strong coke. High indices usually mean better coking behavior. Non-caking coals show little swelling and poor Gray–King ratings; prime coking coals show significant plasticity and coherent coke formation.Step-by-Step Solution:Recognize that agglutination/caking under heat is the essential property for coke quality.Gray–King classification reflects resultant coke texture/strength.FSI quantifies swelling linked to plasticity; higher FSI generally correlates with stronger agglutination.Verification / Alternative check:Industrial practice uses Gray–King, FSI, Gieseler plastometry, and Ruhr dilatometry together to characterize coking coals; these collectively evaluate plastic range, fluidity, and resulting coke strength after reaction (CSR/CRI tests downstream).Why Other Options Are Wrong:Pure “swelling characteristics only” misses the caking interpretation; abradability and impact resistance are mechanical handling properties; ash fusion temperature is determined by separate tests.Common Pitfalls:Assuming high swelling alone guarantees good coke—excessive expansion without coherence can be detrimental; blending strategies balance plasticity and stability.Final Answer:Agglutinating (caking/coking) properties

Question 7

Fuel testing instruments – application of Junker's calorimeter In industrial fuel testing, the Junker's gas calorimeter is specifically used to determine the calorific (heating) value of which class of fuels?

Accepted Answer

Introduction / Context:The calorific value (CV) of a fuel is the amount of heat released during complete combustion. Different calorimeters are optimized for different fuel phases. The Junker's calorimeter is a classic continuous-flow instrument widely used in gas plants, utilities, and laboratories to measure the heating value of town gas, natural gas, and other gaseous mixtures accurately.Given Data / Assumptions:Fuel phase to be tested can be solid, liquid, or gas.Objective is to measure higher or lower heating value under steady conditions.Junker's design employs a burner and a gas–to–water heat exchanger with controlled flow rates.Concept / Approach:In a Junker's calorimeter, the test gas burns at a standardized burner. The combustion products transfer heat to a measured flow of cooling water in a counter-current exchanger. Knowing inlet/outlet water temperatures, water flow rate, and gas flow rate allows calculation of the gas CV from an energy balance: heat gained by water equals heat released by fuel minus sensible and latent corrections where applicable.Step-by-Step Solution:Identify the instrument: Junker's calorimeter is a continuous-flow gas calorimeter.Recognize measurement principle: steady gas firing with exhaust heat captured by water.Match to fuel type: optimized for gaseous fuels, not for coal or heavy oils.Select the correct option accordingly.Verification / Alternative check:Solid and liquid fuels are typically measured using bomb calorimeters (constant-volume) or oil calorimeters; gaseous fuels use Junker's, Boy's, or Parr gas calorimeters.Why Other Options Are Wrong:Pulverised coal: Measured via bomb calorimetry under constant volume with oxygen.Fuel oil: Determined using liquid-fuel (e.g., bomb) calorimeters or combustion-type oil calorimeters.None of these: Incorrect because the instrument is explicitly for gases.Common Pitfalls:Confusing lower vs. higher heating value; gas calorimeters may require condensation correction if water vapor is condensed or not.Final Answer:gaseous fuels

Question 8

Coal combustion on grates – operating and ash factors that accentuate clinkering On a furnace grate burning coal, which condition most strongly promotes clinker formation (sintered ash masses) and aggravates clinkering trouble?

Accepted Answer

Introduction / Context:Clinkering is the formation of hard, fused ash masses on the grate. It disrupts air distribution, reduces combustion efficiency, and increases maintenance. Clinkering depends on ash chemistry (fusion temperature) and on-bed operating temperature, which is governed by air supply and bed management.Given Data / Assumptions:Coal burned on a grate with primary air through the bed.Ash contains oxides (e.g., Fe, Ca, Na, K, Si, Al) influencing fusion temperature.Operating choices include bed thickness, air preheat, and draught intensity.Concept / Approach:Clinkering worsens as the ash approaches or exceeds its softening temperature. This occurs when the local bed temperature is high due to excessive thickness (poor cooling/air distribution) and preheated primary air (raising adiabatic flame temperature near the grate). While ash rich in iron or alkalis can lower ash softening temperature, the single operating condition that directly accentuates clinkering is a hot, thick bed with preheated air.Step-by-Step Solution:Relate clinkering to ash fusion temperature vs. actual bed temperature.Identify operating factors increasing bed temperature: thick bed and preheated air.Note that low forced draught lowers temperature and is less likely to clinker.Choose the condition most clearly aggravating clinkering: thick bed + preheated air.Verification / Alternative check:Plant practice: Reducing bed thickness or air preheat, improving air distribution, and blending high-iron/alkali coals with high-fusion-ash coals mitigates clinkers.Why Other Options Are Wrong:Low forced draught and low temperature: Tend to reduce the risk of ash fusion.Low-reactivity char with Fe/S: Lowers fusion temp but is a fuel property; the question asks which condition accentuates on the grate—operationally (c) is decisive.All of the above: Incorrect because (a) does not accentuate.Common Pitfalls:Confusing slagging in furnaces (radiant zone) with clinkering on grates; though related, the controlling temperatures and air paths differ.Final Answer:Thick fire bed combined with preheated primary air

Question 9

Explosion limits – blast furnace gas safety range Blast furnace gas has explosion limits of 37–71% gas (by volume) in a gas–air mixture. In a confined space, it will explode when its concentration is:

Accepted Answer

Introduction / Context:Explosion (flammability) limits define the composition range over which a fuel–air mixture can ignite and propagate flame. Outside this range, mixtures are either too lean or too rich to sustain combustion. Knowledge of limits is essential for safe handling of industrial gases like blast furnace gas (BFG).Given Data / Assumptions:BFG explosion limits: lower = 37 vol%, upper = 71 vol% fuel in air.Confined space with an ignition source present.Standard pressure and temperature conditions assumed for the stated limits.Concept / Approach:For an explosion to occur, the fuel concentration must lie between its lower explosion limit (LEL) and upper explosion limit (UEL). Below LEL the mix is too lean; above UEL it is too rich (insufficient oxygen). Thus a mixture will explode only when the concentration lies within the quoted range of 37–71%.Step-by-Step Solution:Identify LEL = 37% and UEL = 71% (fuel in air).Explosion possible only for compositions inside [LEL, UEL].Therefore choose “between 37% and 71%”.Verification / Alternative check:Similar interpretation applies to other industrial gases; e.g., methane LEL ≈ 5% and UEL ≈ 15% in air.Why Other Options Are Wrong:> 71%: Too rich; oxygen deficient for propagation.None: Incorrect since a valid range exists.Common Pitfalls:Ignoring that ventilation, temperature, and pressure can shift limits slightly; always design with safety margins.Final Answer:between 37% and 71%

Question 10

Flame temperatures – why actual flame temperature is below adiabatic Why is the measured (actual) flame temperature in furnaces and burners always lower than the calculated adiabatic flame temperature?

Accepted Answer

Introduction / Context:The adiabatic flame temperature is the theoretical maximum temperature achieved when a fuel burns completely with no heat loss to the surroundings. In practice, measured flame temperatures are lower. Understanding the gap between ideal and real conditions is key to burner and furnace design.Given Data / Assumptions:Adiabatic calculation assumes: complete combustion, no heat loss, reactants at reference conditions, and no dissociation constraints.Real flames experience heat transfer to walls, radiation to surroundings, and incomplete mixing.High-temperature dissociation and finite-rate chemistry can also reduce temperature.Concept / Approach:Actual systems depart from adiabatic assumptions in two primary ways: unavoidable heat losses and incomplete combustion (from mixing limitations, residence-time constraints, or local quenching). Additionally, endothermic dissociation at high temperatures reduces equilibrium temperature. These mechanisms ensure the real flame temperature is always below the adiabatic value.Step-by-Step Solution:Start with the adiabatic energy balance: all chemical energy becomes sensible enthalpy of products.Account for heat losses by convection and radiation to walls, refractories, and unburnt streams.Recognize incomplete combustion lowers chemical energy release (unburnt CO, HC).Conclude actual flame temperature Verification / Alternative check:Measured flue gas containing CO or unburnt hydrocarbons indicates incomplete combustion; wall heat flux measurements confirm non-adiabatic operation.Why Other Options Are Wrong:(a) alone is insufficient; complete combustion is achievable in many systems but not universally sustained.(b) alone is true but the combined explanation (c) is fuller and therefore best.(d) contradicts practical observations.Common Pitfalls:Ignoring high-temperature dissociation and finite-rate effects; assuming stoichiometric firing guarantees adiabatic temperatures in practice.Final Answer:Both (a) and (b)

Question 11

Volatile matter in coal – combustion behavior A coal with a high percentage of volatile matter will most likely:

Accepted Answer

Introduction / Context:Volatile matter (VM) is the fraction released as gases and vapors when coal is heated in the absence of air. VM strongly influences ignition characteristics, flame length, smoke formation, and coking behavior. Understanding VM helps in boiler design and selection of suitable combustion systems.Given Data / Assumptions:High-VM coal contains a larger fraction of hydrocarbons and oxygenated volatiles.Combustion system aims for complete burnout with minimal smoke.Carbonisation behavior is also affected by VM (more tar/gas).Concept / Approach:High VM lowers ignition temperature and increases the release of combustible gases early in heating, producing long flames that can be smoky if air–fuel mixing is inadequate. Such coals typically need larger, not smaller, combustion space to complete afterburning of volatiles and reduce smoke. During carbonisation, high-VM coals generate more tar and gas, not less.Step-by-Step Solution:Link high VM to easier ignition and longer flames.Anticipate more tar and gaseous byproducts during carbonisation.Infer that larger combustion chambers or over-fire air may be needed for clean burnout.Select the option that matches these behaviors.Verification / Alternative check:Boiler and kiln practice confirms that high-VM bituminous coals need sufficient secondary air and residence time to oxidize volatiles fully.Why Other Options Are Wrong:Smaller combustion chamber: Opposite of typical design guidance for high VM.Very little tar/gas on carbonisation: High VM yields more tar and gas.All of the above: Contains incorrect statements, so cannot be right.Common Pitfalls:Assuming high VM always means cleaner combustion; without proper air staging, smoke and CO can increase.Final Answer:ignite easily and burn with a long, smoky flame

Question 12

Metallurgical coke quality – effect of high ash in coking coal If coal destined for metallurgical-grade coke production has a higher ash percentage, which consequence is most characteristic for the resulting coke quality?

Accepted Answer

Introduction / Context:Metallurgical coke must be strong and abrasion-resistant to survive handling and to maintain permeability in the blast furnace. The ash present in coking coal directly affects coke strength and increases slag volume in ironmaking. Selecting low-ash coals is therefore a key specification in cokemaking.Given Data / Assumptions:Higher ash in feed coal implies higher inert mineral matter in produced coke.Coke quality indices include hardness, tumbler index, and abrasion (micum) indices.Downstream steel brittleness is more a function of steel impurities and processing than a direct property of the coke product.Concept / Approach:Ash is inert, non-carbon material that weakens the coke matrix, reduces mechanical integrity, and increases fines generation under handling—i.e., lowers abrasion resistance. In the blast furnace, more ash means more slag and higher flux demand, indirectly affecting furnace efficiency. While hardness also tends to deteriorate with high ash, abrasion resistance degradation is the most consistently cited and directly measured adverse effect on coke quality parameters.Step-by-Step Solution:Relate increased ash to reduced carbon matrix continuity.Infer higher fines generation and worse abrasion indices.Recognize that “brittleness in steel” is not a property of coke and is an indirect, downstream issue.Select “decreased abrasion resistance of coke”.Verification / Alternative check:Industry specifications seek low-ash coal to maximize coke strength after reaction (CSR) and minimize abrasion loss (M10/M40 indices).Why Other Options Are Wrong:Decreased hardness: Can occur but abrasion resistance is the more definitive, routinely reported impact.Brittleness in steel: Not a direct consequence tied to coke specification in the context of this question.None of these: Incorrect since a clear adverse effect exists.Common Pitfalls:Confusing coke property changes with metallurgical impacts in steelmaking stages; keep focus on coke quality metrics.Final Answer:Decreased abrasion resistance of coke

Question 13

Coal storage and safety – effects of weathering and spontaneous combustion Improper storage of coal can lead to weathering and even spontaneous combustion. These processes most notably increase the coal's:

Accepted Answer

Introduction / Context:Coal stockpiles are reactive. Oxidation, moisture cycling, and microbial action can cause weathering and, in severe cases, self-heating leading to spontaneous combustion. Understanding property changes aids in designing safe storage and minimizing quality loss.Given Data / Assumptions:Coal stored with inadequate compaction, drainage, or monitoring.Exposure to air and moisture over time.Ambient temperatures that allow low-temperature oxidation.Concept / Approach:Weathering oxidizes coal, increasing oxygen functional groups and making the material more friable (crumbly). Volatile matter may polymerize or oxidize, and the net calorific value decreases due to partial oxidation and moisture gain. Caking properties deteriorate; yields of valuable carbonised products (tar, gas) fall in carbonisation. Thus, the most characteristic increases are in oxygen content and friability.Step-by-Step Solution:Identify primary reaction: low-temperature oxidation of coal in stockpile.Connect oxidation to higher O-content and structural weakening.Note resulting increased friability and reduced fuel quality.Choose the option matching these increases.Verification / Alternative check:Field experience shows weathered coal exhibits higher H/C- and O/C-ratios (more oxygenated groups) and higher fines generation on handling.Why Other Options Are Wrong:Caking index: Generally declines with oxidation.Yield of carbonised products: Decreases, not increases.Calorific value: Decreases due to oxidation and moisture.Common Pitfalls:Assuming spontaneous heating always leads to ignition; often it stops at weathering but quality losses remain significant.Final Answer:friability and oxygen content

Question 14

High-ash coals – reasons for undesirability in boilers and furnaces Why is a high ash content in coal generally undesirable for combustion and metallurgical operations?

Accepted Answer

Introduction / Context:Ash is the incombustible residue of coal. While all coals contain some mineral matter, higher ash percentages degrade performance, raise maintenance costs, and impair product quality in metallurgical furnaces. Understanding the multiple adverse effects explains why fuel buyers specify maximum ash limits.Given Data / Assumptions:Coal is fired in pulverised-fuel boilers or on grates, or used to make coke.Refractory-lined furnaces are subject to thermal cycling.Ash composition can lead to low-melting eutectics.Concept / Approach:High ash increases erosive wear in mills, ducts, and burners. When ash becomes molten or sticky, it can infiltrate refractory linings and, upon cooling, cause spalling due to different expansion coefficients. In metallurgical units, ash elevates slag volume, ties up sulphur/phosphorus, and can deposit on heat-transfer surfaces (slagging/fouling), reducing efficiency and increasing outages. Hence, all listed drawbacks are valid and collectively justify the undesirability of high-ash fuels.Step-by-Step Solution:Relate ash content to increased solids loading → abrasion.Consider molten ash–refractory interactions → spalling risk.Account for slag volume, impurities retention, and heat-transfer fouling.Conclude that all statements are correct.Verification / Alternative check:Plant data show higher ash coals correlate with higher mill wear rates and boiler tube fouling indices; metallurgical plants report increased slag handling and flux consumption.Why Other Options Are Wrong:Any single statement alone is incomplete; all mechanisms contribute.Common Pitfalls:Assuming ash is inert and harmless; its chemistry (iron/alkalis) and melting behavior are critical.Final Answer:All of the above

Question 15

Source of laboratory gas – cracking process Common “laboratory gas” supplied to burners in teaching labs is typically produced industrially by the cracking of which petroleum fraction?

Accepted Answer

Introduction / Context:Laboratory gas, used in Bunsen and Tirrill burners where piped natural gas is unavailable, is produced by thermal cracking of middle-distillate petroleum fractions to generate a combustible gas mixture. Understanding its origin helps in safety and supply planning for laboratories.Given Data / Assumptions:Cracking converts higher hydrocarbons into lighter gases.The target is a steady, clean-burning gaseous fuel with adequate calorific value.Feedstocks may vary; traditional practice emphasizes certain fractions.Concept / Approach:Among petroleum cuts, kerosene is a common feed for portable gas generators used historically in laboratories and field setups. Thermal cracking of kerosene produces a mix of light hydrocarbons (e.g., methane to butenes) suitable for lab burners after cooling and scrubbing. Heavier feeds like fuel oil are less suitable for compact cracking units; gasoline is already volatile and typically not cracked for this purpose; diesel is heavier and produces more coke under simple cracking conditions.Step-by-Step Solution:Identify goal: produce combustible light gases from a mid-distillate feed.Select kerosene as the practical, traditional cracking feed for laboratory gas generation.Reject lighter (gasoline) and heavier (diesel, fuel oil) feeds for this context.Verification / Alternative check:Older laboratory gas generators and field references cite kerosene cracking as a standard method to produce a consistent lab gas stream.Why Other Options Are Wrong:Gasoline: Already light and volatile; not typically cracked for lab gas.Diesel/Fuel oil: Heavier; simple cracking yields more coke and operational issues.Common Pitfalls:Confusing “laboratory gas” with bottled LPG or natural gas; the question refers to gas produced by cracking for lab burners.Final Answer:kerosene

Question 16

Flue gas diagnostics – indicator of incomplete combustion losses When incomplete combustion losses are high in a furnace or boiler, which component will be present in unusually large amounts in the flue gas analysis?

Accepted Answer

Introduction / Context:Stack gas analysis provides rapid feedback on combustion quality. Complete combustion of carbon to carbon dioxide maximizes heat release. When combustion is incomplete, chemical energy remains in partially oxidized products, especially carbon monoxide (CO), indicating losses and safety concerns.Given Data / Assumptions:Fuel contains carbon and possibly hydrogen, sulphur, etc.Combustion air and mixing may be suboptimal (deficient oxygen or poor turbulence).Flue gas analyzer measures CO2, CO, O2 (and often NOx, SO2), and sometimes unburnt hydrocarbons and opacity.Concept / Approach:Incomplete combustion of carbon forms CO when oxygen supply or mixing is inadequate, or when quenching occurs. CO represents unliberated chemical energy because C → CO releases less heat than C → CO2. Therefore, elevated CO in flue gas is the most direct indicator of incomplete combustion loss. High soot can appear, but opacity alone is not a reliable quantitative measure of heat loss; CO2 generally drops when CO rises because carbon is not fully oxidized; excess O2 may simultaneously be high if mixing is poor rather than oxygen-deficient globally.Step-by-Step Solution:Relate complete oxidation: C + O2 → CO2 (maximum heat release).Relate incomplete oxidation: 2C + O2 → 2CO (less heat release, CO present).Identify CO as the principal diagnostic for incomplete combustion losses.Select “CO”.Verification / Alternative check:Combustion tuning aims to minimize CO at acceptable excess O2; efficiency calculations penalize CO and unburnt hydrocarbons in loss accounting.Why Other Options Are Wrong:CO2: Typically decreases when incomplete combustion rises.O2: Can be high due to excess air, but does not by itself indicate losses.C (soot): May increase, but CO is the standard quantitative indicator.Common Pitfalls:Assuming zero O2 implies perfect combustion—low O2 can also imply oxygen deficiency and more CO. Balance both CO and O2 for optimal tuning.Final Answer:CO

Question 17

Combustion thermochemistry: For a typical exothermic combustion process carried out at comparable conditions, the internal energy of the combustion products is __________ relative to that of the reactants.

Accepted Answer

Introduction:Understanding how energy is stored and released in combustion is central to thermodynamics and reactor design. When fuels burn, chemical bonds rearrange and energy is liberated as heat and (often) work. This question focuses on the internal energy comparison between products and reactants for exothermic combustion under comparable reference conditions.Given Data / Assumptions:Combustion is exothermic under standard reference states.Comparison is made at the same reference temperature and pressure unless otherwise stated.No shaft work extraction during the comparison; we are comparing state functions.Concept / Approach:For an exothermic reaction, the change in internal energy is negative at a given temperature: ΔU = U_products − U_reactants Step-by-Step Solution:Write the first law for a reacting system at constant T for state comparison: ΔU = U_p − U_r.Exothermic combustion → ΔU Therefore, U_p Verification / Alternative check:Standard heats of combustion (negative values) tabulated at 25°C imply products are at a lower internal energy level. Any temperature rise during actual combustion is a process effect; when both sides are brought back to the same T, the energy difference remains negative.Why Other Options Are Wrong:More/equal: Contradict exothermicity at equal reference conditions.“Depends on state”: While temperature affects U, at equal reference T the sign is fixed (less).“Indeterminate”: With the exothermic assumption and equal reference T, the determination is clear.Common Pitfalls:Confusing process temperature rise (hot products) with state comparison at the same T; internal energy is a state function, so compare at equal T and P.Final Answer:less

Question 18

Pulverized versus lump coal firing: Compared with burning lump coal, which statement about combustion of pulverized coal in furnaces is correct?

Accepted Answer

Introduction:Pulverized coal firing is widely used in utility boilers because finely ground particles present a very high surface area for rapid devolatilization and combustion. Recognizing how this affects flame characteristics, air requirements, and heat release helps in selecting firing systems and tuning combustion for efficiency and emissions.Given Data / Assumptions:Pulverized coal particles (typically Well-designed burners with good air–fuel mixing.Goal: complete combustion with minimal excess air.Concept / Approach:Fine particles ignite quickly, releasing volatiles and burning more completely over short residence times. Better mixing and rapid kinetics reduce the need for high excess air. Flames are generally hot and often luminous due to incandescent carbon particles. The overall heat release rate per furnace volume is higher, enabling compact boilers with high steaming capacity.Step-by-Step Solution:High surface area → faster reactions → lower required excess air for complete burnout.Rapid combustion → higher flame temperatures (not “low”).Incandescent particles → luminous flame (not “non-luminous”).Intense burning → higher, not lower, volumetric heat-release rate.Verification / Alternative check:Boiler tuning practice shows reduced O2 setpoints and improved efficiency with proper pulverized-fuel milling, classification, and burner staging.Why Other Options Are Wrong:Non-luminous/low-temperature: Opposite of typical pulverized-coal flames.Lower heat release: False; pulverization increases heat release per volume.Reduced efficiency: Properly fired pulverized-coal boilers achieve high efficiencies.Common Pitfalls:Confusing pulverized-coal flames with gaseous, non-sooty premixed flames, which tend to be less luminous.Final Answer:can be done with less excess air

Question 19

Petroleum and fuels basics: Pick the single WRONG statement from the following set about LPG, flash point, fuel gas from distillation, and naphthalene source.

Accepted Answer

Introduction:This question checks key fuel terminology and common industrial facts: how LPG is used, what “flash point” means, approximate fuel-gas generation in crude distillation, and the principal source of naphthalene. It asks you to spot the single incorrect statement.Given Data / Assumptions:LPG composition mainly propane/butane with minor propylene/butylene traces.Flash point vs. fire point distinction.Crude distillation units vent off fuel gas streams of order tens of Nm^3 per tonne.Naphthalene is obtained predominantly from coal tar distillation, not crude oil.Concept / Approach:Evaluate each statement against standard definitions and industry practice. LPG is a versatile fuel and cutting gas (with oxygen). Flash point is a “just ignites briefly” temperature; sustained burning defines the fire point. Crude units produce refinery fuel gas in nontrivial quantities. By contrast, the major commercial source of naphthalene is coal tar from coking operations; crude oil yields are very low.Step-by-Step Solution:Check (a): True—LPG is widely used in vehicles and for heating; with O2, it supports metal cutting/heating.Check (b): True—flash point implies transient ignition, not sustained burning.Check (c): True as an order-of-magnitude statement for refinery fuel gas production.Check (d): False—maximum naphthalene yield comes from coal tar distillation.Check (e): True—LPG cylinders typically contain propane/butane liquefied under pressure.Verification / Alternative check:Textbook definitions and refinery process overviews corroborate the flash-point definition and naphthalene's coal-tar origin.Why Other Options Are Wrong:Only (d) is incorrect; (a), (b), (c), and (e) are accurate.Common Pitfalls:Confusing flash point with fire point, and assuming all aromatics are crude-derived in large quantities.Final Answer:Maximum industrial yield of naphthalene is obtained from crude oil distillation.

Question 20

Fuel interchangeability metric: The “Wobbe index” is primarily a characteristic used for which class of fuels?

Accepted Answer

Introduction:The Wobbe index is a key parameter for assessing whether one fuel gas can substitute for another without changing burner settings. Utilities and industrial users rely on it to maintain safe, efficient combustion across varying gas compositions.Given Data / Assumptions:Wobbe index W = Higher (or lower) heating value divided by the square root of the specific gravity (relative density) of the gas.Burners are orifice-and-pressure based devices sensitive to volumetric energy flow.Concept / Approach:For gas-fired equipment operating at a given pressure drop, volumetric flow changes with gas density. The Wobbe index normalizes heating value by density effect, so fuels with similar W values deliver comparable heat input. Therefore, it is specifically a characteristic of gaseous fuels, not liquids or solids.Step-by-Step Solution:Identify definition of W.Recognize applicability to gas burners and pipelines.Conclude the relevant class is gaseous fuels.Verification / Alternative check:Gas-grid specifications and appliance standards state acceptable Wobbe index ranges to ensure interchangeability.Why Other Options Are Wrong:Solids/liquids/fat coals/biomass slurries: Not used with Wobbe index; other metrics apply.Common Pitfalls:Confusing heating value alone with Wobbe index; W accounts for density effects in gas delivery.Final Answer:gaseous fuels

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