Question 1

In the classic Doctor's sweetening test used for detecting/removing mercaptans in light petroleum products, the Doctor\'s solution is a solution of sodium plumbite prepared in which medium?

Accepted Answer

Introduction: The Doctor's test (and related sweetening process) targets mercaptans in gasoline and kerosene-range streams. Correct identification of the Doctor's solution composition is important for lab testing and historical sweetening methods. Given Data / Assumptions: Doctor's solution contains sodium plumbite (Na2PbO2). Used with elemental sulfur in the classic sweetening step. We seek the solvent/medium in which sodium plumbite is prepared. Concept / Approach: Sodium plumbite is prepared in a strongly alkaline medium. The conventional Doctor's solution is sodium plumbite dissolved in aqueous caustic soda (NaOH). Under alkaline conditions, mercaptans can be converted and the mixture facilitates the qualitative “Doctor test.” Step-by-Step Solution: 1) Recall that plumbites are stabilized in caustic (alkaline) solution.2) Associate the Doctor's solution with NaOH-based preparation.3) Choose the aqueous caustic soda option. Verification / Alternative check: Textbook descriptions and ASTM-style lab write-ups specify sodium plumbite in caustic soda solution for the Doctor test; alcohol or neutral water are not standard for this preparation. Why Other Options Are Wrong: Alcohol/glycerol: Not the conventional medium for Doctor's solution.Neutral water: Insufficient alkalinity for stable plumbite formation.Soda ash: Weaker base; not the standard practice. Common Pitfalls: Confusing the Doctor test with other sweetening or extraction steps that may use different reagents or solvents; the defining feature is sodium plumbite in caustic. Final Answer: Aqueous caustic soda (NaOH solution)

Question 2

In wax refining, deoiling refers specifically to removing entrained/associated oil from slack wax to obtain harder wax grades. Which process is conventionally used for this deoiling step?

Accepted Answer

Introduction: Slack wax from lube refining contains a substantial amount of trapped oil. Deoiling aims to reduce oil content to produce harder wax grades suitable for candles, packaging, and specialty uses. Understanding the classical deoiling method clarifies plant flowsheets and quality control. Given Data / Assumptions: Feed: slack wax containing significant oil. Goal: reduce oil content in the wax phase. Candidate processes: sweating, solvent-based deoiling, and other mechanical/settling approaches. Concept / Approach: Traditional deoiling uses the sweating process: controlled heating causes lower-melting oil-rich portions to liquefy and drain away, leaving a harder, more crystalline wax. Modern plants often complement or replace sweating with solvent deoiling for efficiency and tighter specs, but sweating is the classical, named deoiling step. Step-by-Step Solution: 1) Identify the specific operation called “deoiling” in wax practice.2) Recognize sweating as the established method for oil removal by selective melting and drainage.3) Select “Sweating (controlled warming and drainage)” as the correct option. Verification / Alternative check: Industry references distinguish sweating (deoiling) from solvent dewaxing/deoiling used on lube oils; many wax refineries historically used sweating to meet oil content specs. Why Other Options Are Wrong: Solvent extraction only: While solvent deoiling exists, the specifically named traditional deoiling operation for wax is sweating.Resettling: Does not selectively remove oil based on melting behavior.All of the above / Acid treating: Over-broad or unrelated to deoiling by selective melting. Common Pitfalls: Confusing wax sweating (deoiling) with lube-oil dewaxing or generic solvent extraction; process names are similar but applied differently. Final Answer: Sweating (controlled warming and drainage)

Question 3

Hydrofining (a hydroprocessing step using hydrogen and a catalyst) is widely regarded as one of the most recent and highly effective refinery methods—identify the principal purpose it serves among common options such as sulphur removal, smoke point …

Accepted Answer

Introduction / Context: Hydrofining is a refinery hydrotreating operation in which oil is contacted with hydrogen over a catalyst to upgrade quality. The core aim is to remove reactive hetero-atoms and stabilize the product. This question asks you to pinpoint the single most important objective among several plausible refinery improvements. Given Data / Assumptions: Process: hydrofining (hydrotreating under H2 with catalyst) Candidate effects: sulphur removal, smoke point improvement, breathing loss reduction, viscosity-index (VI) improvement Feed types: naphtha, kerosene, diesel, VGO, etc., as typically hydrotreated Concept / Approach: Hydrofining promotes hydrogenolysis and hydrogenation reactions. Hetero-atoms (S, N, O) are converted to H2S, NH3, and H2O and removed. Olefins and certain aromatics are hydrogenated, improving stability and sometimes smoke point. However, among the listed outcomes, deep sulphur removal (hydrodesulphurization, HDS) is the defining purpose that enables fuels to meet sulphur specifications and emissions norms. Step-by-Step Solution: 1) Identify hallmark reaction family: HDS (hydrodesulphurization).2) Recognize co-benefits: saturation of olefins → stability; partial aromatic saturation → better smoke point in kerosene.3) Compare options and select the principal, specification-driven objective: sulphur removal. Verification / Alternative check: Fuel regulations (e.g., low-sulphur diesel/gasoline) are met by hydrotreaters designed primarily for sulphur removal; other properties improve secondarily. Why Other Options Are Wrong: Improvement of smoke point: often improves for kerosene but is a secondary effect.Reduction of breathing loss: a storage/tank venting issue, not a reactor conversion objective.Improvement of viscosity index: VI relates to lube base oils; hydrotreating may affect it slightly, but it is not the core goal here. Common Pitfalls: Confusing secondary property improvements with the primary compliance-driven purpose (sulphur removal). Final Answer: Removal of sulphur

Question 4

A petroleum reservoir rock must allow hydrocarbons to be stored and to flow economically to wells. Which property (or combination) best characterizes a good reservoir: low porosity, high permeability, high porosity, or the combination of high porosi…

Accepted Answer

Introduction / Context: Reservoir engineering hinges on two foundational rock properties: porosity (storage space) and permeability (flow capacity). A productive petroleum reservoir must provide sufficient pore volume to hold fluids and adequate connectivity between pores so oil and gas can move to the wellbore. Given Data / Assumptions: Rock types can vary (sandstones, carbonates, fractured formations). Hydrocarbon production requires both storage and deliverability. Economic rates depend strongly on permeability. Concept / Approach: Porosity is the fraction of bulk rock volume occupied by voids. Permeability measures the ease with which fluids flow through interconnected pores. High porosity without permeability traps hydrocarbons; high permeability with low porosity yields limited volumes. Optimal reservoirs typically exhibit both properties at favorable levels. Step-by-Step Solution: 1) Map storage requirement → high porosity.2) Map deliverability requirement → high permeability.3) Conclude that the desirable combination is high porosity and high permeability. Verification / Alternative check: Classic reservoir performance equations (e.g., Darcy’s law for flow; material balance for volumes) implicitly require adequate φ (porosity) and k (permeability) to achieve commercial production rates and reserves. Why Other Options Are Wrong: Low porosity: inadequate storage volume for economic recovery.High permeability only: good flow but limited oil in place without sufficient porosity.High porosity only: ample storage but poor deliverability and low production rates. Common Pitfalls: Assuming one property compensates fully for the other; in practice, both are needed for a good reservoir. Final Answer: Both high porosity and high permeability

Question 5

Among statements about aromatics, specific gravity, and gross calorific value (GCV) trends for petrofuels, identify the single incorrect statement by comparing density–GCV relations on weight and volume bases.

Accepted Answer

Introduction / Context: Fuel property trends link composition, density, and heating value. Understanding how specific gravity correlates with GCV on both mass (kcal/kg) and volume (kcal/litre) bases helps avoid common misconceptions when comparing fuels of different cut ranges. Given Data / Assumptions: ρ denotes specific gravity at 15.5°C. Comparison across typical refinery fuels (naphtha → diesel → heavy fractions). Generalized empirical correlations capture GCV dependence on ρ. Concept / Approach: As fuels get heavier (higher ρ), their hydrogen content usually decreases (higher C/H), so GCV per kilogram tends to drop slightly. However, per litre, heavier fuels can deliver similar or greater energy because density is higher. Therefore, “heavier gives higher GCV per kg but lower per litre” is reversed from the typical trend and is the incorrect statement here. Step-by-Step Solution: 1) Recognize heavier → higher ρ → generally lower GCV (kcal/kg).2) Higher density can raise energy per litre even when kcal/kg falls.3) Hence the statement claiming “higher per kg but lower per litre” is wrong. Verification / Alternative check: Standard refinery property tables and correlations indicate declining mass-based GCV with increasing density and often stable/higher volume-based GCV for heavier cuts. Why Other Options Are Wrong (i.e., not the incorrect one): Aromatics vs paraffins: aromatics typically have higher density.GCV correlation: forms like 12400 - 2100*ρ^2 (kcal/kg) capture the inverse relation with density.Higher ρ → higher C/H ratio: heavier fractions are relatively carbon-rich. Common Pitfalls: Confusing mass-based with volume-based comparisons; always specify the basis for calorific value. Final Answer: Heavier petrofuels have higher GCV on a weight basis but lower GCV on a volume basis.

Question 6

Kerosene quality is judged strongly by clean burning and high smoke point. Among i-paraffins (iso-paraffins), aromatics, n-paraffins, and naphthenes, select the most desirable hydrocarbon family for good quality kerosene.

Accepted Answer

Introduction / Context: Kerosene performance in lamps and jet/household uses is tied to smoke point and combustion cleanliness. Hydrocarbon family composition influences smoke formation, odor, and stability. This item asks which family is most desirable overall for kerosene quality. Given Data / Assumptions: Families considered: n-paraffins, i-paraffins, aromatics, naphthenes. Quality metric emphasized: smoke point/clean burning behavior. Normal handling and storage conditions implied. Concept / Approach: Aromatics generally depress smoke point and are undesirable for kerosene burning quality. Paraffins (normal and iso) and naphthenes burn cleaner; among these, naphthenes are widely cited as desirable for kerosene because they help deliver higher smoke points and good combustion stability relative to aromatics. (Note: exact optimal mix depends on multiple specs; aromatics are clearly least desirable.) Step-by-Step Solution: 1) Eliminate aromatics due to poor smoke point.2) Compare paraffins and naphthenes for burning quality.3) Choose naphthenes as the most desirable family for high-quality kerosene. Verification / Alternative check: Refining texts link high smoke point kerosenes to lower aromatics and adequate naphthenic/paraffinic content; naphthenes are often favored for lamp-burning properties. Why Other Options Are Wrong: Aromatics: low smoke point, soot formation.n-Paraffins: cleaner than aromatics but not as favored as naphthenes for smoke point.i-Paraffins: good volatility traits but overall kerosene quality prioritizes reduced aromatics and sufficient naphthenes. Common Pitfalls: Assuming octane-related reasoning applies; kerosene quality focuses on smoke point, not spark-ignition octane. Final Answer: Naphthenes

Question 7

Visbreaking is applied to heavy fuel oils/residua primarily to make handling and use easier. Identify the key property it targets for reduction—considering pour point, viscosity, and pumping pressure drop.

Accepted Answer

Introduction / Context: Visbreaking is a mild thermal cracking process applied to heavy residues to make them more marketable and easier to handle. It achieves limited conversion without excessive gas/coke formation and is common ahead of blending bunker fuels or selling fuel oil grades. Given Data / Assumptions: Feed: atmospheric or vacuum residue/heavy fuel oil. Objective: improve handling and product value. Measured properties: viscosity, pour point, pumpability. Concept / Approach: The defining specification improved by visbreaking is viscosity. By cracking large molecules to smaller ones, viscosity falls markedly, enabling compliance with viscosity-grade limits. While pumpability and sometimes pour point can benefit indirectly, these are secondary consequences of viscosity reduction and blending strategies. Step-by-Step Solution: 1) Identify visbreaking as mild thermal cracking for residue.2) Link cracking severity to viscosity drop as the principal target property.3) Recognize pumpability/pour-point improvements as ancillary; choose “Viscosity.” Verification / Alternative check: Product specifications for fuel oils heavily emphasize viscosity grades; visbroken residue is commonly blended to meet them. Why Other Options Are Wrong: Pour point: not the primary controlled outcome of visbreaking; dewaxing/winterization targets pour point directly.Pressure drop on pumping: derivative of viscosity; not the core process objective.All of (a), (b), and (c): overbroad; the primary targeted specification is viscosity. Common Pitfalls: Assuming every property that improves indirectly is a primary process target; focus on the specification that drives the operation design. Final Answer: Viscosity

Question 8

Industry practice reports pour point in standardized increments and defines it via a prescribed cooling/tilt procedure. Choose the correct statement about how pour point is expressed and defined.

Accepted Answer

Introduction / Context: The pour point test determines the lowest temperature at which an oil will just flow under specified test conditions. Results are reported in discrete increments, with conventions differing between Celsius and Fahrenheit reporting. Given Data / Assumptions: Standardized laboratory procedure (e.g., ASTM D97 or equivalent). Reporting may be in °C or °F depending on region. Concept / Approach: Under ASTM methods, pour point values are reported to the nearest 3°C increment (… , −12°C, −9°C, −6°C, −3°C, 0°C, 3°C, …). In Fahrenheit terms, this corresponds to increments of 5°F (… , 10°F, 5°F, 0°F, −5°F, −10°F, …). Therefore, saying “multiple of 3°F” is incorrect, while “multiple of 5°F” is correct. The definition is not “5°C below the temperature at which oil ceases to flow”; rather, it is the lowest temperature at which movement is observed under the test’s tilt protocol. Step-by-Step Solution: 1) Recall reporting increments: 3°C steps, equivalent to 5°F steps.2) Identify that 3°F is not a standard increment.3) Reject the misdefinition involving “5°C below weeping cessation.” Verification / Alternative check: Method descriptions and reporting guidelines show 3°C (≈5°F) increments; lab sheets round to these discrete values. Why Other Options Are Wrong: 3°F multiple: not aligned with standard reporting intervals.5°C below no-flow: not the procedural definition.None of these: incorrect because 5°F increments are correct. Common Pitfalls: Confusing reporting increments with cooling step sizes; follow the method’s specified rounding. Final Answer: Pour point is reported as a multiple of 5°F.

Question 9

Clay treatment (adsorptive finishing) is used on various petroleum streams. Identify the effect it is chiefly known for among the following: decolorising and stabilising cracked gasoline, desulphurising straight-run gasoline/kerosene, adsorbing arse…

Accepted Answer

Introduction / Context: Clay (activated clay/earth) finishing is an adsorption process applied to selected petroleum fractions to remove color bodies, gums, and polar contaminants. It is especially associated with improving appearance and stability of cracked gasolines and certain distillates. Given Data / Assumptions: Media: acid-treated/activated clays with high surface area. Streams: cracked gasoline, sometimes kerosene/light distillates. Targets: color bodies, olefinic polymers, trace oxygenates, and polar species. Concept / Approach: Clay treatment is primarily an adsorptive polish. It is not a chemical desulphurization process; sulphur reduction to specification typically requires hydrotreating or sweetening. While certain metals can be adsorbed by specialized guard beds (e.g., alumina or proprietary sorbents), arsenic removal for reforming is not a standard role for clay finishing in this context. Step-by-Step Solution: 1) Identify the classic application: stabilising and decolorising cracked gasoline.2) Eliminate “desulphurises”: clay is not a primary sulphur-removal method.3) Eliminate “adsorbs arsenic for reforming”: specialized metal traps are used instead.4) Therefore, choose the cracked-gasoline stabilization/decolorisation effect. Verification / Alternative check: Finishing sections in refinery processing texts list clay towers for color/gum reduction on cracked naphthas and kerosenes, not for deep sulphur removal or arsenic trapping for reformers. Why Other Options Are Wrong: Desulphurises SR gasoline/kerosene: significant sulphur reduction requires hydrotreating/sweetening.Adsorbs arsenic for reforming: typically handled by dedicated metal-guard beds, not general clay finishing.All of the above: overstates clay’s scope beyond its main adsorption polish function. Common Pitfalls: Assuming any adsorbent removes all contaminants; adsorption is selective and often limited for sulphur/metals versus hydrogenation routes. Final Answer: Decolorises and stabilises cracked gasoline

Question 10

Expand the full and correct form of the common fuel acronym “LPG”. Choose the standard international expansion used in refining, distribution, and safety documentation.

Accepted Answer

Introduction / Context: LPG is a widely used fuel comprising mainly propane and butane (and their mixtures). The correct standardized expansion is important in technical documentation, labeling, and regulations. Given Data / Assumptions: Common variants appear in everyday usage. We must select the internationally accepted technical term. Concept / Approach: Standards and safety codes (transport, storage, MSDS) consistently use “Liquefied petroleum gas.” Note the spelling “Liquefied,” not “Liquified,” and “petroleum,” not “petrol.” The term reflects gas that has been liquefied by compression/cooling for storage and transport. Step-by-Step Solution: 1) Eliminate “liquid petrol gas”: “petrol” denotes gasoline, not LPG.2) Eliminate misspelling “liquified.”3) Choose “Liquefied petroleum gas.” Verification / Alternative check: Product datasheets and regulatory references consistently adopt “Liquefied petroleum gas (LPG).” Why Other Options Are Wrong: Liquid petroleum gas: not the standard phrasing; emphasis is on the liquefaction process.Liquified petrol gas: incorrect spelling and “petrol” is wrong substance.Liquid petrol gas: incorrect terminology for this mixture. Common Pitfalls: Confusing gasoline (“petrol”) with LPG constituents; propane/butane are distinct from gasoline fractions. Final Answer: Liquefied petroleum gas

Question 11

In vacuum crude distillation, the heaviest non-vaporized stream leaves the column bottom. Select the correct technical term commonly used for this bottom product.

Accepted Answer

Introduction / Context: Crude distillation is performed first at near-atmospheric pressure and then, for heavier cuts, under vacuum. The bottom stream from the vacuum column consists of the highest boiling components that do not distill even under reduced pressure. Given Data / Assumptions: Unit: vacuum distillation column (VDU). Stream of interest: column bottoms (heaviest fraction). Naming conventions vary across refineries. Concept / Approach: The accepted term for the vacuum bottoms stream is “residuum” (often “vacuum residue,” “VR,” or “vacuum resid”). “Reduced crude” generally refers to the atmospheric column bottoms (after lighter components are removed). “Residual crude” is non-standard/ambiguous terminology, and “petrolatum” is a waxy by-product distinct from VDU bottoms. Step-by-Step Solution: 1) Associate vacuum column bottoms with the term “residuum.”2) Distinguish “reduced crude” as atmospheric bottoms, not vacuum bottoms.3) Exclude “petrolatum” and “residual crude” as incorrect labels here. Verification / Alternative check: Typical refinery stream maps label VDU bottoms as VR/residuum; downstream uses include asphalt, feed to visbreaker/coker, or deasphalting. Why Other Options Are Wrong: Reduced crude: atmospheric unit bottom stream, not VDU bottom.Petrolatum: semi-solid waxy material; not the generic name for VDU bottoms.Residual crude: imprecise and non-standard wording. Common Pitfalls: Mixing up AU (atmospheric) and VDU terminology; always specify the unit when naming bottom streams. Final Answer: Residuum

Question 12

Among common refinery products—naphtha, kerosene, low-sulphur heavy stock (LSHS), and furnace oil—identify which typically contains the minimum sulphur under normal processing and product specifications.

Accepted Answer

Introduction / Context: Sulphur in petroleum products affects emissions, catalyst life, and product quality. Different fractions exhibit different sulphur levels based on crude slate and extent of hydrotreating. This question asks you to pick the product that, in practice, has the lowest sulphur content among typical marketed fuels. Given Data / Assumptions: Products compared: naphtha, kerosene, LSHS, furnace oil. Typical modern refining includes hydrotreating of light streams. “Minimum sulphur” refers to typical finished product specifications from a standard fuels refinery. Concept / Approach: Light fractions such as naphtha are readily hydrotreated to very low sulphur levels (often to near-zero for petrochemical feed specs). Kerosene is also commonly hydrotreated, but specs can be higher than for petrochemical-grade naphtha. Heavy stocks like furnace oil and even LSHS retain substantially more sulphur than light hydrotreated streams, despite “low-sulphur” labeling relative to other heavy fuels. Step-by-Step Solution: 1) Rank streams by ease of desulphurization: naphtha > kerosene > heavy fuel oils.2) Recognize that LSHS, though “low sulphur” for heavy stock, still exceeds naphtha levels.3) Choose naphtha as having the minimum sulphur in typical practice. Verification / Alternative check: Refinery product specifications and hydrotreating outcomes show naphtha achieving the lowest sulphur targets (especially when destined for reforming/petrochemicals). Why Other Options Are Wrong: Kerosene: hydrotreated but typically not as low as petrochemical-grade naphtha.LSHS: low for a heavy stock, still far higher than light hydrotreated products.Furnace oil: among the highest sulphur levels in marketed fuels. Common Pitfalls: Letting the “low-sulphur” label of LSHS mislead you; it is low relative to other heavy fuels, not relative to light hydrotreated streams. Final Answer: Naphtha

Question 13

Petroleum fuels knowledge check: For typical straight-run gasoline (petrol) blended for spark-ignition engines, what is the approximate average molecular weight range of the overall mixture under standard refinery characterisation?

Accepted Answer

Introduction / Context: Petrol (gasoline) is not a single compound but a complex mixture of hydrocarbons, mainly in the carbon number window C5 to about C12. Refiners often characterise such mixtures through average or pseudo-component properties, including average molecular weight, to guide design, blending, and engine performance expectations. Given Data / Assumptions: Straight-run gasoline range roughly C5–C12 with paraffins, isoparaffins, naphthenes, and aromatics. Average properties are mixture-averaged and depend on crude source and processing severity. We seek a typical, practical range used in teaching and design problems. Concept / Approach: Molecular weight scales approximately with carbon number. For C5–C12 families, the molecular weights of the constituents span about 72 (pentanes) to 170+ (dodecanes/aromatics). A blend centred around C7–C9 will average near 100–120. Hence, an educationally accepted gasoline average molecular weight lies in the 100–130 band, allowing normal blending variability. Step-by-Step Solution: 1) Identify typical carbon window for petrol: C5–C12.2) Map to molecular weights: about 72 (C5) to 170+ (C12/aromatics).3) Average around C7–C9 components gives ~100–120.4) Choose the option range that captures this typical average: 100–130. Verification / Alternative check: Property tables for gasoline cuts in refinery handbooks routinely show average molecular weight values near 100–110 for common straight-run or mildly processed blendstocks, confirming the order of magnitude. Why Other Options Are Wrong: (a) 40–60 corresponds to light naphtha/solvent ranges closer to C3–C4/C5 extremes, not whole gasoline pools.(c) 250–300 would imply very heavy fractions far beyond the gasoline boiling range.(d) 350–400 is characteristic of vacuum gas oils or resids, not petrol.(e) 160–190 is too high for a petrol pool centred on C7–C9. Common Pitfalls: Confusing component molecular weight with mixture average, or assuming a single fixed value rather than a practical range driven by crude and process severity. Final Answer: 100–130

Question 14

Fundamentals of catalytic cracking: Identify the correct qualitative outcome associated with the catalytic cracking process for producing gasoline from heavier feedstocks.

Accepted Answer

Introduction / Context: Catalytic cracking converts heavy gas oils into lighter products including gasoline with superior antiknock quality. Compared with thermal cracking, catalytic routes favour reactions that increase branching and aromatics, improving octane ratings of the gasoline fraction. Given Data / Assumptions: Feed: vacuum gas oils or heavy distillates. Process: fluid catalytic cracking (FCC) as the archetype. Qualitative comparisons to thermal cracking outcomes. Concept / Approach: Catalysts promote skeletal isomerization, cyclization, and dehydrogenation/aromatization. The result is a gasoline richer in isoparaffins and aromatics, giving higher octane. Operating pressure is typically low to moderate (close to atmospheric in FCC risers), so a blanket statement of “very high pressure and temperature” is misleading. Gum tendency is lower than for purely thermal cracking when measured under controlled stabilization and treatment, though cracked gasoline is more olefinic than straight-run and still needs care in handling. Step-by-Step Solution: 1) Determine which listed effect is characteristic of catalytic cracking.2) Elevated aromatics (and isoparaffins) in cracked gasoline are expected and directly raise octane → supports option (c).3) Exclude options inconsistent with practice: very low octane (false), very high pressure (false for FCC), systematically “very high gum” (overstated/false relative to thermal).4) Select the correct qualitative descriptor. Verification / Alternative check: Standard refinery texts describe FCC gasoline as higher in aromatics and olefins than straight-run with improved octane number due to increased ring structures and branching. Why Other Options Are Wrong: (a) Octane is higher, not very low.(b) Pressure is not “very high”; temperatures are high but typical for cracking, and pressure is relatively low.(d) Gum formation risk is managed; thermal gasoline typically has worse gum tendencies.(e) Although qualitatively close, it is broader than the stem allows; the key attribute commonly emphasized is increased aromatics content. Common Pitfalls: Assuming any “cracked” gasoline must always have extreme gum levels or that severe operating conditions automatically mean high pressure in FCC. Final Answer: Gasoline obtained has very high aromatic content

Question 15

Crude classification terminology: Which base type of crude oil is commonly referred to as an asphaltic crude in refinery practice?

Accepted Answer

Introduction / Context: Refineries often classify crude oils based on the predominance of hydrocarbon families: paraffinic, naphthenic, or mixed. This classification guides expectations for product slates, residue properties, and asphalt yield during processing. Given Data / Assumptions: Asphaltic residues arise when heavier polycyclic and polar components concentrate in the bottom fractions. Naphthenic crudes are typically richer in cycloparaffins and polycyclic materials. Terminology reflects observed residue characteristics. Concept / Approach: Naphthenic-base crudes yield residues with higher asphaltene content and are therefore commonly called asphaltic crudes. Paraffinic crudes tend to produce waxy residues and higher paraffin content in distillates. Mixed crudes sit between these extremes and “aromatic” is not a standard crude base label in this context. Step-by-Step Solution: 1) Link crude base family to residue character.2) Naphthenic base → asphaltene-rich residues → asphaltic behaviour.3) Choose the base type associated with asphaltic crudes: naphthenic. Verification / Alternative check: Refinery handbooks routinely equate naphthenic-base crudes with asphaltic character and paraffinic-base crudes with waxy character. Why Other Options Are Wrong: (a) Paraffinic crudes are waxier, not asphaltic.(c) Mixed is an intermediate label, not specifically asphaltic.(d) “Aromatic” is not the conventional crude base classification in this context.(e) Hybrid wording adds no standard meaning and is not used for the asphaltic designation. Common Pitfalls: Confusing high aromatic content in products with the “aromatic” label for crude base; the conventional pairings are paraffinic (waxy) vs naphthenic (asphaltic). Final Answer: Naphthenic

Question 16

Origins of petroleum — theory check: Which theory for the origin of petroleum fails to account for the presence of nitrogen and sulphur compounds commonly observed in crude oil?

Accepted Answer

Introduction / Context: Crude oils contain heteroatoms such as nitrogen and sulphur bound within complex molecules (e.g., pyridines, porphyrins, thiophenes). A sound origin theory should plausibly explain how such heteroatoms entered and persisted in the organic matrix during geological transformation. Given Data / Assumptions: Modern and Engler theories are organic-origin models. Carbide theory is an inorganic-origin proposal (e.g., metal carbides reacting with water to form hydrocarbons). Observed crude composition includes N and S species of biological provenance. Concept / Approach: Organic origin models derive petroleum from biological matter (plankton, algae) that naturally contains nitrogen and sulphur in biomolecules; diagenesis and catagenesis concentrate and transform these into the heteroatom species found in crude. The inorganic carbide theory does not naturally account for these heteroatoms, making it inconsistent with the compositional evidence. Step-by-Step Solution: 1) Compare theories on their ability to explain heteroatoms.2) Organic models: straightforward path from biogenic N and S to crude heteroatoms.3) Carbide (inorganic) model: lacks a mechanism for significant N and S incorporation.4) Conclude that the carbide theory fails this explanatory test. Verification / Alternative check: Biomarkers such as porphyrins (linked to chlorophyll/hemoproteins) argue strongly for organic origin and explain nitrogen presence; sulphur arises from biological sulphur cycles and sulphate-reducing environments. Why Other Options Are Wrong: (a) Modern organic theory explains N and S well.(c) Engler’s organic hypothesis likewise aligns with heteroatom evidence.(d) Not all listed theories fail; only the carbide theory is inconsistent here.(e) Cosmic dust accretion is not a mainstream petroleum origin model and is not pertinent to standard curricula. Common Pitfalls: Assuming all origin theories are equally capable of explaining composition; inorganic pathways struggle with ubiquitous biogenic markers. Final Answer: Carbide (inorganic) theory

Question 17

Controls on petroleum formation (organic origin): Which factor listed below does not principally govern the mechanism by which petroleum forms from organic matter in sediments?

Accepted Answer

Introduction / Context: Petroleum generation from organic matter proceeds through diagenesis, catagenesis, and metagenesis. The key controls are biochemical activity, temperature history, pressure, and time, which together drive the transformation of kerogen into liquid and gaseous hydrocarbons. Given Data / Assumptions: Organic source material deposited in sedimentary basins. Transformation occurs under burial with limited oxygen. We focus on primary governing factors. Concept / Approach: Bacterial action (especially anaerobic) and thermal maturation are central to early and middle stages. Pressure and time enable compaction, expulsion, and continued reactions. Soil pH, while locally affecting near-surface environments, is not a principal control on deep subsurface kerogen maturation pathways traditionally emphasized in petroleum geology. Step-by-Step Solution: 1) List major controls: biology (bacteria), heat, pressure, and time.2) Evaluate “pH of the soil”: not a principal subsurface maturation control in standard models.3) Select the factor that does not govern the mechanism materially. Verification / Alternative check: Academic summaries of petroleum systems emphasize temperature history, time, pressure, and biological mediation; pH appears mainly in surface diagenesis contexts and is not a headline control on generation kinetics. Why Other Options Are Wrong: (b) Bacterial action is important during early diagenesis.(c) Heat drives cracking of kerogen to oil and gas.(d) Pressure aids compaction/expulsion and influences phase behaviour.(e) Time allows these processes to proceed to completion. Common Pitfalls: Over-attributing near-surface geochemical factors like soil pH to deep basin maturation processes. Final Answer: pH of the soil

Question 18

Acid alkylation practice: Why is sulphuric acid concentration maintained between 90% and 98% in refinery alkylation units producing high-octane alkylate?

Accepted Answer

Introduction / Context: Acid alkylation combines light isoparaffins (e.g., isobutane) with olefins (e.g., propylene, butylenes) to produce high-octane alkylate. Sulphuric acid (H2SO4) units require careful control of acid strength to keep desired alkylation pathways dominant and to suppress side reactions that harm yield and product quality. Given Data / Assumptions: H2SO4 concentration is operationally kept near 90–98%. Main goal: favour carbocation pathways to form branched C7–C9 alkylate. Undesired side reactions include polymerisation and cracking. Concept / Approach: At too low acid strength (< 90%), the medium inadequately stabilises desired intermediates and promotes polymerisation/oligomerisation of olefins, increasing acid consumption and creating heavy ends. At too high acid strength (> 98%), excessive acidity and dehydration tendencies shift pathways toward cracking and other side reactions, lowering selectivity to high-quality alkylate. Therefore, the accepted operating window balances these effects. Step-by-Step Solution: 1) Consider reaction network sensitivity to acidity.2) Low acid strength: polymerisation dominates → poor selectivity.3) Excessive acid strength: cracking side reactions escalate.4) The practical window 90–98% minimises both extremes → validates both (a) and (b). Verification / Alternative check: Operating manuals for H2SO4 alkylation specify tight acid strength control with regular acid regeneration to maintain optimal selectivity and manageable acid consumption rates. Why Other Options Are Wrong: (a) Alone is incomplete; high-end effect must also be considered.(b) Alone is incomplete without the low-end behaviour.(d) Incorrect; both effects are well documented.(e) Alkylate is a hydrocarbon; water solubility is not the control objective. Common Pitfalls: Treating acid strength as “the higher the better”; in reality, too-high strengths increase side reactions and corrosion concerns. Final Answer: both (a) and (b)

Question 19

Gasoline quality additives: Which of the following is commonly used as an antiknock additive or blending component that improves octane in spark-ignition fuels?

Accepted Answer

Introduction / Context: Antiknock quality (octane number) measures a fuel’s resistance to auto-ignition under spark-ignition conditions. Refiners and blenders use components with high octane to improve gasoline performance and meet regulatory standards. Given Data / Assumptions: Focus is on SI engine antiknock improvement (octane). Historically, tetraethyl lead was used; modern practice includes oxygenates like ethanol. We choose among the listed species. Concept / Approach: Alcohols such as ethanol possess high blending octane numbers and act as oxygenates that can raise the octane of gasoline pools. Mercaptans are odourants (not antiknock agents). Pyridine is a nitrogenated base chemical, not used for octane improvement. Amyl nitrate is known as a diesel ignition improver (cetane improver), which has the opposite goal—reducing ignition delay—not the antiknock role in gasoline. Step-by-Step Solution: 1) Identify components with high octane blending value: alcohols.2) Exclude diesel-centric additives (amyl nitrate).3) Exclude non-antiknock, non-blending agents (mercaptans, pyridine).4) Select the option that correctly improves octane in gasoline. Verification / Alternative check: Fuel standards and blending guides cite ethanol’s high RON/MON and widespread use as an octane enhancer and oxygenate. Why Other Options Are Wrong: (a) Amyl nitrate targets diesel cetane, not gasoline octane.(c) Mercaptans serve as odorants for leak detection in LPG/natural gas, not antiknock agents.(d) Pyridine is not employed to raise gasoline octane.(e) Carbon disulphide is not a standard gasoline antiknock additive. Common Pitfalls: Mixing up octane improvers (SI engines) with cetane improvers (CI engines); they aim at opposite ignition behaviours. Final Answer: Alcohols (e.g., ethanol)

Question 20

Flow assurance for waxy crudes: Chemical additives are commonly used when handling waxy crude oils mainly to achieve which operational objective?

Accepted Answer

Introduction / Context: Waxy crudes exhibit high pour points due to crystallisation of paraffinic components at lower temperatures, causing flow problems in pipelines and storage. Chemical additives are a practical mitigant alongside thermal management and insulation strategies. Given Data / Assumptions: Additives include pour point depressants and flow improvers. Objective is to maintain pumpability and reduce gelling. We assess the primary practical purpose in field operations. Concept / Approach: Pour point depressants modify wax crystal morphology and growth so that crystals remain smaller and less interlocked, reducing the apparent yield stress and pour point of the crude. They do not dissolve or chemically remove wax from the crude; rather, they alter crystallisation behaviour to improve flow properties under cooling. Step-by-Step Solution: 1) Identify the dominant transport problem: wax crystallisation raising pour point.2) Match mechanism: polymeric additives inhibit crystal agglomeration.3) Result: lower measured pour point and better cold-flow. Verification / Alternative check: Flow assurance literature documents significant pour point reductions achievable with tailored depressants, often combined with pipeline heating or insulation. Why Other Options Are Wrong: (b) Additives do not truly dissolve wax; solubility is temperature-controlled.(c) Intent is not to precipitate wax at source; that would worsen transport.(d) No routine chemical removal of wax from the bulk crude occurs via such additives.(e) Neutralising naphthenic acids is a different corrosion-focused treatment. Common Pitfalls: Expecting additives to eliminate wax content; they optimise flow behaviour rather than altering crude composition substantially. Final Answer: depress the pour point

Petroleum Refinery Engineering Questions