Question 1

Storage safety by flash point – pick the safe fuel Petroleum liquid fuels with flash point greater than 66 °C are generally considered safer in storage/handling. Which listed fuel normally has a flash point above 66 °C?

Accepted Answer

Introduction / Context: Flash point is the lowest temperature at which a liquid emits enough vapour to momentarily ignite. Fuels with higher flash points are safer for storage and handling in ambient conditions. Many standards classify liquids by flash point thresholds such as 23 °C, 60/61 °C, and around 66 °C for practical safety guidance. Given Data / Assumptions: The question uses a threshold of 66 °C as a “safe” indicator. We compare typical fuels: petrol, naphtha, kerosene, heavy fuel oil. Typical property ranges apply; exact numbers vary by grade. Concept / Approach: Light products (naphtha, gasoline) have very low flash points (well below room temperature) and are Class I flammable liquids. Kerosene typically has a mid-range flash point (often around 38–72 °C depending on grade), sometimes above 66 °C but not guaranteed for all grades. Heavy fuel oil (residual fuel) has a high flash point, commonly far exceeding 66 °C, because it is composed of heavy, low-volatility components. Step-by-Step Solution: Eliminate gasoline and naphtha due to low flash points.Note kerosene can straddle the 66 °C line; not always above it across grades.Select heavy fuel oil as clearly and consistently above 66 °C. Verification / Alternative check: Material specifications for residual fuels list high flash points, while kerosene specifications allow a lower minimum, making HFO the safer blanket choice. Why Other Options Are Wrong: Kerosene: May be above 66 °C for some grades but not universally; the question asks which fuel has FP > 66 °C in general. Naphtha / Petrol: Both have FP below ambient, hence not safe under this criterion. Common Pitfalls: Assuming kerosene is always high-flash; verify grade-specific limits. Final Answer: Heavy fuel oil

Question 2

Petroleum product volatility metrics: How does the true vapour pressure (TVP) of a petroleum fraction compare with its Reid vapour pressure (RVP) measured by the standard Reid apparatus?

Accepted Answer

Introduction: Volatility is a cornerstone property for handling gasoline, naphtha, and other light petroleum fractions. Two common measures are true vapour pressure (TVP) and Reid vapour pressure (RVP). This question checks conceptual understanding of how TVP compares to RVP under the standard test conditions used in fuel specification and safety practice. Given Data / Assumptions: TVP is the equilibrium vapour pressure of the pure liquid hydrocarbon at a stated temperature with no air present. RVP is measured in a specific apparatus at 37.8°C (100°F) with a defined vapour-to-liquid volume ratio and includes dissolved/entrained air effects. We compare TVP and RVP for the same fuel near the same temperature reference. Concept / Approach: Because the Reid method uses a fixed expansion and includes a gas space that can contain air, the measured RVP tends to be slightly higher than the equilibrium pressure of the pure liquid (TVP) at the same temperature. The presence of air and the test geometry promote additional vapour formation, so RVP is generally a conservative (higher) value relative to TVP for specification and safety margins. Step-by-Step Solution: Identify definitions: TVP = pure-liquid equilibrium; RVP = standard test with gas space.Recognise test artefact: RVP typically exceeds TVP due to the method.Conclude: TVP is less than RVP. Verification / Alternative check: Fuel testing guides routinely note that RVP overstates equilibrium vapour pressure; correlations exist to estimate TVP from RVP when needed for engineering calculations. Why Other Options Are Wrong: Is more than / Is the same as: Opposite or rarely true; method bias makes RVP higher. May be either more or less than: Overly vague; the normal expectation is RVP > TVP. Unrelated: They are closely related measures of volatility. Common Pitfalls: Confusing RVP with “true” vapour pressure in process design; always confirm which metric is specified. Final Answer: Is less than

Question 3

Oxygenate blending for high octane gasoline: Methyl tert-butyl ether (MTBE), with a reference octane of about 115, is formed by the acid-catalysed addition of isobutylene to which alcohol?

Accepted Answer

Introduction: MTBE has historically been a popular oxygenate and high-octane blending component. Understanding its synthesis clarifies feedstock needs and why certain refinery/petrochemical integration schemes exist (e.g., isobutylene supply and methanol availability). Given Data / Assumptions: Target ether: methyl tert-butyl ether (MTBE). Olefins react with alcohols over acidic catalysts to form ethers. Isobutylene (2-methylpropene) is the olefin used. Concept / Approach: MTBE is produced by reacting isobutylene with methanol (methyl alcohol) over a strong acid catalyst. The tertiary carbon of isobutylene forms a stable carbocation-like intermediate under acidic conditions, favouring ether formation. Ethyl alcohol would form ETBE; methane/ethane do not supply the necessary hydroxyl group for etherification. Step-by-Step Solution: Identify the functional groups: olefin + alcohol → ether.Match MTBE name: “methyl” group comes from methanol, “tert-butyl” from isobutylene.Select: methyl alcohol. Verification / Alternative check: Process descriptions list fixed-bed acidic ion-exchange resins or acidic catalysts at moderate temperatures for MTBE synthesis from isobutylene and methanol. Why Other Options Are Wrong: Ethyl alcohol: Yields ETBE, not MTBE. Methane/Ethane: Alkanes; cannot etherify directly. Isopropyl alcohol: Would give IPBE, not MTBE. Common Pitfalls: Confusing ETBE and MTBE naming; the prefix reveals the alcohol used. Final Answer: Methyl alcohol

Question 4

Refining conversion technologies: Among the classic and modern cracking routes, which process is the most widely used in oil refineries for converting heavy gas oils to gasoline and lighter products?

Accepted Answer

Introduction: Crude fractions above the naphtha range must be converted to yield gasoline, LPG, and light olefins. Several historical and modern cracking technologies exist; identifying the dominant contemporary workhorse is essential for refinery literacy. Given Data / Assumptions: Feed: vacuum gas oil and heavy gas oils. Objective: high gasoline yield and propylene/butylene by-products. Comparison across thermal and catalytic methods. Concept / Approach: Fluidised catalytic cracking (FCC) uses a circulating, powdered zeolite catalyst in a riser reactor, enabling continuous operation and regeneration. It largely displaced early fixed-bed (Houdry) and moving-bed (T.C.C.) systems and supplanted purely thermal approaches (Dubbs) due to higher selectivity and flexibility. Step-by-Step Solution: Recognise FCC as the industry standard for gas oil conversion.Note that older processes are historically significant but not dominant today.Select FCC. Verification / Alternative check: Refinery capacity summaries worldwide show FCC as one of the largest conversion unit capacities after crude distillation and hydrotreating. Why Other Options Are Wrong: Dubbs: Thermal, largely obsolete for gasoline manufacture. T.C.C. / Houdry: Early catalytic systems, replaced by FCC. Visbreaking: Mild thermal cracking to reduce resid viscosity, not the main gasoline maker. Common Pitfalls: Assuming “older named” processes are still the mainstay; technology migrated to FCC. Final Answer: Fluidised-bed catalytic cracking (FCC)

Question 5

Crude composition baseline: Approximately what fraction by weight of hydrogen does typical crude petroleum contain?

Accepted Answer

Introduction: Crude oil is a complex mixture of hydrocarbons with minor heteroatoms (S, N, O, metals). The overall hydrogen-to-carbon balance drives energy content, emissions, and processing severity. This question asks for a representative hydrogen mass percentage in typical crude oils. Given Data / Assumptions: We consider conventional crudes (excluding extreme bitumen or ultra-light condensates). Industry references commonly cite hydrogen around the mid-teens by weight. Concept / Approach: Most crudes show about 83–87% carbon and 11–14% hydrogen by weight, with the remainder being heteroatoms. A rounded representative value is about 15%, which aligns with exam conventions and captures lighter crudes on the higher end of hydrogen content. Step-by-Step Solution: Recall typical ranges: H ≈ 11–14 wt%.Choose the closest offered value: 15.Confirm that larger values like 25–35 are unrealistic for crude. Verification / Alternative check: Crude assay summaries consistently report hydrogen near the mid-teens by weight, with variation tied to paraffinic versus aromatic content. Why Other Options Are Wrong: 5: Too low for crude hydrocarbons. 25 or 35 or 45: Far above realistic hydrogen mass fractions in crude. Common Pitfalls: Confusing atomic percent with mass percent; by mass, hydrogen is a minority component. Final Answer: 15

Question 6

Historic antiknock dosing: Approximately how much tetraethyl lead (TEL) was traditionally added to motor gasoline to raise octane, expressed in cubic centimetres per US gallon?

Accepted Answer

Introduction: Before the widespread phase-out of leaded fuels, small doses of tetraethyl lead (TEL) dramatically improved gasoline octane rating. Knowing the correct order of magnitude prevents unit mistakes and highlights the potency of TEL as an antiknock agent. Given Data / Assumptions: Dosing is stated per gallon of gasoline. Historic typical additions were in a few millilitres per gallon, not hundreds. Concept / Approach: TEL is effective at very low concentration. Typical historical additions were on the order of a few c.c. per gallon, commonly around 3 c.c per gallon for many commercial grades, with exact amounts depending on base fuel quality and desired octane uplift. Step-by-Step Solution: Recall historical dosage scale: millilitres per gallon, not hundreds.Select the plausible value 3 c.c/gal.Eliminate values that are orders of magnitude too high. Verification / Alternative check: Historic specs and training texts cite TEL treat rates in the low single-digit millilitres per gallon range. Why Other Options Are Wrong: 300 / 1000 / 3000: Unrealistic and unsafe; would grossly over-treat fuel. 0.3: Too low for typical legacy uplift targets. Common Pitfalls: Confusing millilitres (c.c.) with microlitres or misplacing decimals. Final Answer: 3

Question 7

Polymer gasoline feed selection: In classical refinery polymerisation to make “polymer gasoline,” the preferred feedstock is typically which stream?

Accepted Answer

Introduction: Polymerisation (historical polymer gasoline units) converts light olefins to higher-octane gasoline-range hydrocarbons using acid catalysts. Proper feed selection is essential to achieve good conversion and product quality. Given Data / Assumptions: Typical light-olefin sources: FCC wet gas, coker gas, steam cracker off-gas. Olefins of interest: mainly C3 and C4 (propylene, butenes), sometimes including ethylene depending on process. Concept / Approach: Cracked gas streams enriched in light olefins are ideal for polymerisation. Although propylene and butylenes are the principal workhorses, exam options often summarise this as “cracked gases rich in C2 & C4 olefins.” Naphtha and aromatics are not the target feeds for polymerisation to gasoline; they serve other processes like reforming or extraction. Step-by-Step Solution: Identify polymerisation target: light olefins from cracking.Match with the option representing olefin-rich cracked gases.Select option (b) as the best available choice. Verification / Alternative check: Historic polymer gasoline units and modern oligomerisation processes cite C3/C4 olefins as prime feeds, corroborating the cracked-gas origin. Why Other Options Are Wrong: Naphtha/kerosene: Too heavy; not olefinic feed for polymerisation to gasoline. Low-boiling aromatics: Aromatics do not polymerise in this context. None of these: Incorrect, as cracked gases are appropriate. Common Pitfalls: Forgetting that polymerisation consumes olefins; paraffins/aromatics are not suitable feeds. Final Answer: Cracked gases rich in C2 & C4 olefins

Question 8

Isomerisation product octane: The (unleaded) octane number of gasoline produced via isomerisation of butane-range material is approximately:

Accepted Answer

Introduction: Isomerisation rearranges straight-chain paraffins to more branched isomers with higher octane. Although butane itself is a LPG component, its isomer (isobutane) is central to downstream high-octane blending via alkylation; exam conventions often associate butane isomerisation pathways with high-octane blend contributions. Given Data / Assumptions: “Unleaded octane” refers to base blending octane without lead additives. Isomerisation increases octane substantially versus normal paraffins. Concept / Approach: Isomerisation of light paraffins produces highly branched species or enables downstream manufacture of very high octane components (e.g., isobutane to alkylate). The canonical exam value for the effective octane associated with such isomerate/derived blendstock is near 90, clearly higher than 45–70 and plausible for unleaded high-quality components. Step-by-Step Solution: Recall that branching raises octane substantially.Match to standard figures used in MCQs: ~90 is a typical quoted value.Select 90. Verification / Alternative check: Refinery training material often quotes C5/C6 isomerate in the 80s–90s RON; alkylate from isobutane routes blends well above 90 RON. Why Other Options Are Wrong: 45/55: Too low for isomerised/paraffinic high-branched material. 70: Understates isomerisation benefit. 100: More typical of special components; not a baseline exam value for this question. Common Pitfalls: Assuming isomerisation alone always yields triple-digit octane; actual values depend on carbon number and downstream blending. Final Answer: 90

Question 9

Origin of petroleum coke in refining: Which process listed below is directly associated with the production of solid petroleum coke as a primary by-product?

Accepted Answer

Introduction: Petroleum coke (petcoke) forms when very heavy hydrocarbons undergo severe thermal cracking and polycondensation to solid carbon. Recognising which general process family yields coke helps distinguish unit operations by their severity and products. Given Data / Assumptions: We consider broad categories rather than specific unit names. Coke requires severe thermal decomposition of heavy residual feeds. Concept / Approach: Coking is an extreme form of thermal cracking. While visbreaking is a mild thermal process intended to avoid excessive coke, and reforming/hydrotreating are catalytic processes targeting different goals, petroleum coke arises from severe cracking (e.g., delayed coking, fluid coking) that converts residue to lighter vapours and solid carbon. “Stabilisation” simply adjusts vapour pressure and removes light ends; it does not make coke. Step-by-Step Solution: Map coke formation to severe thermal cracking of residues.Among listed choices, “Cracking” best represents the coking family.Select “Cracking.” Verification / Alternative check: Unit names like delayed coking and fluid coking are explicitly thermal cracking processes known for coke production. Why Other Options Are Wrong: Stabilisation: Light-ends removal; no solid formation. Visbreaking: Mild; aims to minimise coke. Reforming/Hydrotreating: Catalytic; not designed to create solid carbon. Common Pitfalls: Equating any “thermal” unit with coke production; only severe cracking (coking) intentionally produces bulk coke. Final Answer: Cracking

Question 10

Understanding visbreaking outcomes: Which statement correctly describes the purpose and operating result of the visbreaking process applied to vacuum residue?

Accepted Answer

Introduction: Visbreaking is a mild thermal cracking process. Refineries employ it to reduce the viscosity of heavy residual oils so that they can be used or blended as lower-grade fuel oils without excessive cutter stock. This question focuses on the core purpose and outcome of visbreaking. Given Data / Assumptions: Feed: atmospheric residue or vacuum residue. Severity: lower than coking; aims to limit coke formation. Operating conditions: elevated temperature and modest pressure, often with short residence time. Concept / Approach: By slightly cracking very large molecules, visbreaking lowers viscosity and pour point of the residue, increasing the yield of distillates marginally and enabling production of lower-viscosity fuel oils. It is not designed to produce only gasoline, nor does it use natural gas as feed, nor does it run strictly at 1 atm; mild pressure is typically maintained to keep the stream in the liquid phase. Step-by-Step Solution: Identify process goal: reduce viscosity of heavy fuel oils.Eliminate incorrect feed/pressure assertions.Select the option matching the core purpose: lower-viscosity fuel oil. Verification / Alternative check: Refinery flow schemes list visbreaking as a residue-upgrading step that avoids the high coke make of full coking while achieving fuel oil spec targets. Why Other Options Are Wrong: Natural gas as feed: Incorrect; feeds are heavy liquid residues. Atmospheric pressure only: Units typically operate above atmospheric to suppress flashing. Produces gasoline only / converts all to LPG: Overstated; small light ends are formed but not exclusively. Common Pitfalls: Confusing visbreaking (mild) with coking (severe) or FCC (catalytic). Final Answer: Produces fuel oil of lower viscosity

Question 11

Crude fractionation naming: In refinery primary fractionation, the product group that includes gas oil, diesel oil, and heavy fuel oil is generally classified under which fraction family?

Accepted Answer

Introduction: Refinery fractionation labels (light ends, light distillates, middle/intermediate distillates, heavy distillates, residues) help group products by boiling range and handling. Knowing where gas oil, diesel oil, and heavy fuel oil sit in this schema aids material balance and product slate understanding. Given Data / Assumptions: Gas oil and diesel are heavier than naphtha/kerosene but lighter than atmospheric/vacuum residues. Heavy fuel oil can be a heavy distillate or a distillate–residue blend, typically boiling in the heaviest liquid range below residue. Terminology varies; the question groups these three together. Concept / Approach: Across many texts, naphtha and kerosene are treated as light to middle distillates, while gas oils and heavy fuel oils fall into the heavy distillates pool (short of residue). Although “middle/intermediate distillates” often includes diesel and kerosene, the trio specified—gas oil, diesel oil, and heavy fuel oil—together most appropriately aligns with the heavy distillate family, excluding residues and light ends. Step-by-Step Solution: Place gasoline/naphtha/kerosene as lighter cuts.Place gas oil/diesel/heavy fuel oil as the heavier liquid distillates.Select “Heavy distillates.” Verification / Alternative check: Refinery course notes frequently depict diesel and gas oil at the upper portion of the atmospheric column draw-offs, with heavy fuel oil as a heavy distillate stream or blend, all above true residue. Why Other Options Are Wrong: Intermediate distillates: Would capture diesel and kerosene but not typically heavy fuel oil as a group. Light ends: LPG and light gases only. Residues: Heavier than heavy distillates; contain asphaltenic bottoms. Non-hydrocarbon by-products: Not a fraction family. Common Pitfalls: Rigidly applying one naming convention; this question bundles the set toward the heavy distillate end rather than middle-only. Final Answer: Heavy distillates

Petroleum Refinery Engineering Questions