Question 1

Product colour, refinement, and quality indicators: Pick the statement that is incorrect regarding the colour and related qualitative cues of petroleum products.

Accepted Answer

Introduction / Context: Colour is a simple visual attribute often recorded for petroleum products (e.g., ASTM colour). While it provides rough indications, engineers must avoid over-interpreting colour as a proxy for other properties like viscosity, which require direct measurement. Given Data / Assumptions: Different products show characteristic colours based on refining and contaminant levels. Viscosity depends on molecular weight distribution and temperature, not just colour. Adulteration screening may use fluorescence or UV behaviour. Concept / Approach: Although lighter cuts are usually paler and also happen to have lower viscosity than heavy fuels, the inference “pale → low viscosity” is not a reliable rule for arbitrary samples. Additives, dyes, and contaminants can alter colour independently of viscosity. Thus, the categorical claim in option (a) is incorrect, whereas the other statements reflect cautious, qualified relationships. Step-by-Step Solution: 1) Evaluate (a): claims a direct property linkage that does not hold universally → incorrect.2) (b): colour can indicate refinement to some extent (e.g., removal of resins/asphaltenes).3) (c): as a trend, heavier residua are darker; lighter distillates are paler → generally true.4) (d): fluorescence tests are indeed used in adulteration checks.5) (e): prudent qualifier that colour alone is insufficient → true. Verification / Alternative check: Product specifications for viscosity rely on kinematic viscosity tests (e.g., D445), independent of ASTM colour; standards treat colour as indicative only. Why Other Options Are Wrong: (b) Reasonable as a qualitative cue (not definitive).(c) Reflects common refinery experience.(d) Fluorescence/UV response is a valid screening tool.(e) Correctly notes the need for proper tests. Common Pitfalls: Treating visual colour as a surrogate for viscosity or performance; always confirm with standardized lab methods at controlled temperature. Final Answer: A pale colour of a petroleum product indicates lower viscosity.

Question 2

Produced fluids at the wellhead: As crude oil initially emerges from an oil well, the associated water content can be as high as approximately what percentage before field separation and treatment?

Accepted Answer

Introduction / Context: Crude oil produced at the wellhead commonly carries formation water and emulsions. The water cut varies widely with reservoir conditions and production history. Before separation and treatment, engineers must anticipate realistic ranges to design facilities and plan dehydration steps. Given Data / Assumptions: Question targets a typical upper bound used in foundational coursework and MCQs. Field practice uses separators, heaters, and electrostatic treaters to reduce water content. Heavy water cuts can occur late in field life but may not represent the introductory textbook benchmark. Concept / Approach: Introductory references often cite up to about 10 percent water content in crude as it leaves the well, prior to surface separation. While mature fields can exhibit much higher water cuts, the educational “rule-of-thumb” upper bound for initial separation design examples is commonly around 10 percent for crude streams entering first-stage separators. Step-by-Step Solution: 1) Recognise variability in water cut across reservoirs and production stages.2) Apply the commonly taught upper range for pre-treated crude in basic problems: ~10%.3) Select the nearest matching option. Verification / Alternative check: Basic petroleum production texts cite orders of magnitude for water content and stress the need for separation; 10% is a frequently used design figure in example problems. Why Other Options Are Wrong: (a) and (b) Understate plausible pre-treatment water content.(d) and (e) While possible in late-life wells, these high values exceed the typical “as it comes out” benchmark used in foundational questions. Common Pitfalls: Confusing textbook design figures with extreme field cases; actual water cuts can be much higher but are not the standard assumption for basic MCQs. Final Answer: 10 percent

Question 3

Lubricating oils: In refinery and lube-blending practice, a “multigrade” lubricating oil refers to an oil formulated to maintain suitable flow at low temperature and sufficient film strength at high temperature, which effectively means an oil having…

Accepted Answer

Introduction / Context: Multigrade lubricating oils are designed to perform across a wide temperature range, flowing adequately when cold while still protecting components when hot. The key property that enables this dual behavior is a high viscosity index, supported by base oil selection and viscosity index improvers. Given Data / Assumptions: Term: “multigrade” as used in engine and industrial lubricants (e.g., SAE 10W-30). We compare several oil properties: viscosity, aniline point, flash point, and viscosity index. Goal: identify which property being “high” characterizes multigrade behavior. Concept / Approach: Viscosity index (VI) expresses how little an oil’s viscosity changes with temperature. A higher VI means the oil thickens less at low temperatures and thins less at high temperatures, enabling one formulation to cover multiple “grades” in standardized classifications. Step-by-Step Solution: Step 1: Recall that cold-crank flow and hot protection require controlled viscosity-temperature behavior.Step 2: Recognize VI as the canonical measure of viscosity-temperature sensitivity.Step 3: Conclude that multigrade oils are characterized by a high viscosity index. Verification / Alternative check: SAE multigrade oils achieve low-temperature cranking limits and high-temperature kinematic viscosity targets with polymers and high-VI base stocks, confirming the role of a high VI. Why Other Options Are Wrong: Viscosity: A single viscosity value does not capture behavior across temperatures. Aniline point: A solvency/aromaticity indicator, not a multigrade criterion. Flash point: Relates to volatility and safety; does not define multigrade behavior. Common Pitfalls: Confusing absolute viscosity at one temperature with viscosity-temperature stability; multigrade is about the latter. Final Answer: Viscosity index

Question 4

Catalytic reforming chemistry: In standard petroleum reforming, which core transformation is emphasized for octane improvement?

Accepted Answer

Introduction / Context: Catalytic reforming upgrades low-octane naphtha to high-octane reformate for gasoline blending and produces hydrogen for hydrotreating. Understanding the principal chemistry clarifies product quality shifts and hydrogen make. Given Data / Assumptions: Feed: straight-run or hydrotreated naphtha (C6–C8 range typical). Objective: improve octane number substantially. Reactions occur over bifunctional catalysts (metal/acid sites). Concept / Approach: Key octane-boosting paths include dehydrogenation of naphthenes to aromatics and isomerization of paraffins. Among these, conversion of naphthenes to aromatics gives especially large octane gains and coproduces hydrogen. Step-by-Step Solution: Step 1: Identify ring dehydrogenation of cycloalkanes (naphthenes) as a dominant route.Step 2: Recognize aromatics have much higher octane than corresponding naphthenes.Step 3: Select “Naphthenes into aromatics.” Verification / Alternative check: Typical reformer yields show increased aromatics (e.g., toluene, xylenes) and significant hydrogen production, confirming the transformation. Why Other Options Are Wrong: Naphthenes → paraffins / olefins: Not the signature high-octane pathway. Olefins → paraffins: Hydrogenation may occur but does not define reforming’s octane improvement. Common Pitfalls: Confusing reforming with isomerization or cracking; reforming is not primarily a carbon number change process. Final Answer: Naphthenes into aromatics

Question 5

LPG odorization: Ethyl mercaptan is added to Doctor-negative LPG to aid leak detection by odor. What is the typical target treat rate (ppm by volume) used in practice?

Accepted Answer

Introduction / Context: LPG is naturally odorless. For safety, an odorant such as ethyl mercaptan is added so even small leaks are detectable by smell in domestic and industrial use. Given Data / Assumptions: Product: Doctor-negative LPG (sweet, low sulphur). Odorant: ethyl mercaptan added at a controlled trace level. Units: parts per million (ppm) by volume equivalent. Concept / Approach: Odorization balances detectability with handling safety and product quality. Regulatory and industry guidance typically specify a low two-digit ppm range to ensure recognizability without excessive sulphur addition. Step-by-Step Solution: Step 1: Recall common practice values in the ~10–50 ppm band.Step 2: Among the options, 50 ppm is the only realistic figure consistent with standard odorization targets.Step 3: Select 50 ppm. Verification / Alternative check: Operational guidelines and national safety codes often cite approximately 20–50 ppm as typical treat rates, confirming the order of magnitude. Why Other Options Are Wrong: 1 ppm: Too low for reliable human detection in varied conditions. 5000 / 10000 ppm: Excessive and impractical; would severely affect sulphur specification and odor intensity. Common Pitfalls: Confusing mg/m^3 and ppm or assuming higher is always better; overdosing has drawbacks. Final Answer: 50

Question 6

Catalytic reforming overview: Select the correct statement about reforming with naphtha feed and its impact on gasoline quality, molecular weight, and yield.

Accepted Answer

Introduction / Context: Catalytic reforming upgrades straight-run or hydrotreated naphtha to higher-octane reformate, also generating hydrogen for refinery hydrotreaters. Given Data / Assumptions: Feed: naphtha-range hydrocarbons. Primary goal: raise octane for gasoline blending. Product slate: aromatics-rich reformate, plus hydrogen. Concept / Approach: Reforming reactions (dehydrogenation of naphthenes, isomerization of paraffins, limited hydrocracking) largely conserve carbon number distribution in the gasoline range, so average molecular weight changes modestly compared to deep cracking processes. Yield of gasoline-range components and quality (octane) both improve. Step-by-Step Solution: Step 1: Confirm naphtha as the standard reformer feed.Step 2: Note that reforming is not a heavy cracking process; molecular weight shifts are moderate.Step 3: Recognize uplift in octane and typically favorable gasoline-range yield. Verification / Alternative check: Reformer mass balances show significant RON increase with hydrogen make, while product remains in gasoline boiling range. Why Other Options Are Wrong: Each of (a), (b), and (c) is correct individually; the most complete and correct choice is the combined statement. Common Pitfalls: Confusing reforming with FCC/hydrocracking, which can strongly change molecular weight distribution. Final Answer: All of (a), (b) and (c).

Question 7

Lube refining: Which treatment produces appreciable improvement in the viscosity index (VI) of lubricating oil by selectively removing low-VI components?

Accepted Answer

Introduction / Context: Lubricating oil base stocks require good viscosity-temperature behavior. Refining steps aim to remove components that degrade VI, oxidation stability, or low-temperature flow. Given Data / Assumptions: Objective: appreciable increase in VI. Processes considered: acid, solvent extraction, alkali, and clay treatment. Feed: lube distillates prior to dewaxing/finishing. Concept / Approach: Solvent extraction (e.g., with furfural or N-methyl-2-pyrrolidone) removes aromatics and polar compounds that depress VI. This yields raffinate with higher VI, often followed by dewaxing and hydrotreating/ hydrofinishing. Step-by-Step Solution: Step 1: Identify components harmful to VI (aromatics, polars).Step 2: Use selective extraction to move these into the extract phase.Step 3: Resulting raffinate shows appreciably higher VI. Verification / Alternative check: Process data consistently show VI uplift after solvent extraction compared to untreated distillates. Why Other Options Are Wrong: Acid treatment: Historical sludge/asphaltene removal and color improvement; limited VI uplift. Alkali treatment: Neutralizes acidic impurities; does not appreciably raise VI. Clay treatment: Adsorptive finishing mainly for color/trace impurities; small VI effect. Common Pitfalls: Assuming dewaxing alone defines VI; dewaxing targets pour point, while extraction targets solvency profile affecting VI. Final Answer: Solvent extraction

Question 8

Thermal cracking tendency: Among common hydrocarbon families, which is generally the easiest to crack under comparable conditions?

Accepted Answer

Introduction / Context: Cracking severity and selectivity depend on molecular structure. Process designers assess relative crackability to predict yields in thermal or catalytic operations. Given Data / Assumptions: Comparison across four families: paraffins, naphthenes, olefins, aromatics. General behavior under cracking conditions (not a specialized catalyst exception). Concept / Approach: Straight-chain paraffins have relatively weak C–C bonds and fewer stabilizing resonance effects, making β-scission favorable. Aromatics are most resistant due to aromatic ring stability. Naphthenes and olefins are intermediate. Step-by-Step Solution: Step 1: Rank stability: aromatics > olefins/naphthenes > paraffins.Step 2: Less stable structures crack more readily; therefore paraffins are easiest to crack.Step 3: Choose paraffins. Verification / Alternative check: FCC/thermal data show higher cracking rates for long-chain paraffins compared to cyclic/aromatic species. Why Other Options Are Wrong: Aromatics: Most resistant to cracking. Naphthenes / Olefins: Intermediate; easier than aromatics but harder than paraffins on average. Common Pitfalls: Assuming double bonds make olefins easiest; allylic stabilization and competing pathways complicate the picture compared to straight paraffins. Final Answer: Paraffins

Question 9

Hydrocarbon formulas: Under standard textbook conventions, the general formula CnH2n corresponds to which hydrocarbons?

Accepted Answer

Introduction / Context: Recognizing empirical formulas helps classify petroleum hydrocarbons and anticipate properties relevant to refining and product performance. Given Data / Assumptions: Formula: CnH2n with n ≥ 2. Families under consideration: olefins (alkenes) and cycloalkanes (naphthenes). Open-chain versus cyclic structures are both possible. Concept / Approach: For saturated open-chain alkanes the formula is CnH2n+2. Introducing one double bond (alkenes) or forming a single ring (cycloalkanes) reduces hydrogen count by two, giving CnH2n. Thus both alkenes and cycloalkanes share CnH2n as their general formula. Step-by-Step Solution: Step 1: Recall alkenes: one double bond → CnH2n.Step 2: Recall cycloalkanes: ring formation removes two hydrogens → CnH2n.Step 3: Conclude both families fit the formula. Verification / Alternative check: Examples: C6H12 can represent 1-hexene (olefin) or cyclohexane (naphthene), confirming the shared formula. Why Other Options Are Wrong: Olefins only / Cycloalkanes only: Each excludes the other valid family. Neither: Incorrect because both match. Common Pitfalls: Assuming a unique mapping from formula to structure; structural isomerism and rings yield multiple families with the same empirical formula. Final Answer: Both olefins (alkenes) and cycloalkanes (naphthenes)

Question 10

Fuel rating basics: In the octane number scale used for gasoline, what value is assigned to normal heptane (n-heptane)?

Accepted Answer

Introduction / Context: Octane number quantifies the knock resistance of gasoline in spark-ignition engines. It is defined by comparing a test fuel to a blend of iso-octane and n-heptane under standardized conditions. Given Data / Assumptions: Reference fuels: iso-octane and n-heptane. Scale anchors: iso-octane set high, n-heptane set low. Measurement methods: RON and MON (principles similar for the scale reference). Concept / Approach: By definition, iso-octane is assigned octane number 100 as the high-knock-resistance reference, and n-heptane is assigned octane number 0 as the low-resistance reference. Real fuels are compared to equivalent blends between these anchors. Step-by-Step Solution: Step 1: Recall scale endpoints: iso-octane = 100, n-heptane = 0.Step 2: Select the assigned value for n-heptane = 0.Step 3: Confirm that other values are distractors. Verification / Alternative check: Standard fuel testing handbooks and ASTM methods state the same scale definition. Why Other Options Are Wrong: 100: Assigned to iso-octane, not n-heptane. 70: Arbitrary; not a reference endpoint. Infinity: Not used in octane scaling. Common Pitfalls: Confusing cetane scale (diesel ignition quality) with octane; they are opposite in their performance meaning. Final Answer: 0

Question 11

Hydrogen-to-carbon balance: For hydrocarbons with the same carbon number, which family has the highest hydrogen-to-carbon ratio by weight?

Accepted Answer

Introduction / Context: The hydrogen-to-carbon (H/C) ratio influences combustion cleanliness, smoke tendency, and product properties. For a fixed carbon number, more saturation generally means higher hydrogen content. Given Data / Assumptions: Families: paraffins (saturated acyclic), naphthenes (cycloalkanes), olefins (alkenes), and aromatics. Comparison at equal carbon count. Basis: weight ratio. Concept / Approach: Paraffins are fully saturated (CnH2n+2) with the maximum hydrogen content for a given n. Cyclization or unsaturation reduces hydrogen count (to CnH2n for naphthenes and olefins). Aromatics have even lower H/C due to ring unsaturation. Step-by-Step Solution: Step 1: Write general formulas: paraffins CnH2n+2; naphthenes/olefins CnH2n; aromatics approximately CnH2n−6 for one ring.Step 2: Compare hydrogen per carbon; paraffins are highest.Step 3: Select paraffins. Verification / Alternative check: Elemental analyses confirm higher hydrogen wt% for paraffins versus cyclic/unsaturated counterparts at the same n. Why Other Options Are Wrong: Naphthenes / Olefins: Each has fewer hydrogens than paraffins for the same n. Aromatics: Lowest H/C among the listed families. Common Pitfalls: Mixing atomic and weight ratios; the ordering remains the same for typical carbon numbers. Final Answer: Paraffins

Question 12

Aniline point interpretation: A high aniline point measured for a petrodiesel sample most strongly indicates which compositional character?

Accepted Answer

Introduction / Context: Aniline point is the minimum temperature at which equal volumes of aniline and a petroleum fraction are completely miscible. It is widely used as a qualitative indicator of aromaticity versus paraffinity. Given Data / Assumptions: Measured property: aniline point, relatively high value. Sample: diesel-range fuel. Interpretation sought: what composition does a high aniline point suggest? Concept / Approach: Aromatics are more soluble in aniline than paraffins. Therefore, higher aromatic content depresses the aniline point, while higher paraffinic content elevates it. A high aniline point thus indicates a paraffinic character. Step-by-Step Solution: Step 1: Recall: high aniline point ↔ low aromaticity ↔ high paraffinity.Step 2: Map this directly to the diesel sample’s composition.Step 3: Choose the option indicating “highly paraffinic in nature.” Verification / Alternative check: Correlations between aniline point, diesel index, and smoke point show that paraffinic fuels tend to have higher aniline points and better smokeless burning behavior. Why Other Options Are Wrong: Highly aromatic: Would correspond to a low aniline point. Very low diesel index / very poor ignition quality: Diesel index often rises with paraffinity; the statements do not follow from a high aniline point. Common Pitfalls: Assuming aniline point gives a quantitative aromatic percentage; it is qualitative and comparative. Final Answer: It is highly paraffinic in nature.

Question 13

Alkylation in gasoline manufacture: Which of the following statements about the isobutane–olefin alkylation process in petroleum refining is incorrect?

Accepted Answer

Introduction: Alkylation in refining combines light olefins (e.g., propene, butenes) with isobutane to produce highly branched isoparaffins (alkylate) used as premium gasoline blendstock. The question asks you to identify the incorrect statement about operating principles and outcomes of this process. Given Data / Assumptions: Feedstocks: isobutane and C3–C4 olefins. Catalysts: strong liquid acids in commercial practice. Output: high-octane, low-olefin, low-sulphur alkylate. Concept / Approach: Liquid-acid alkylation is a low-temperature process. Typical reactor temperatures are near ambient to moderately low (often 0–15°C for H2SO4 units and 25–40°C for HF units), nowhere near “very high” temperatures of 1000°C. Such extreme temperatures are associated with pyrolysis/steam cracking, not alkylation. Step-by-Step Solution: Check (a): True — objective is to make a larger isoparaffin (alkylate) with high octane.Check (b): True — commercial catalysts are HF or H2SO4. (AlCl3 routes exist historically/lab, but not standard modern commercial practice.)Check (c): False — alkylation is low-temperature; the statement is incorrect.Check (d): True — alkylate RON typically ~94–98; blending can yield ~90+ gasoline easily.Check (e): True — alkylate is prized for clean, paraffinic, high-RON properties. Verification / Alternative check: Process descriptions for HF/H2SO4 alkylation specify low temperatures and moderate pressures to maximise selectivity and minimise acid consumption and side reactions. Why Other Options Are Wrong: (a), (b), (d), (e) are correct statements about commercial alkylation and its product qualities. Common Pitfalls: Confusing alkylation with steam cracking/pyrolysis; assuming “reaction = high temperature.” Final Answer: All alkylation processes operate at very high temperatures (> 1000°C).

Question 14

Flash point fundamentals for liquid fuels: The flash point of a liquid petroleum fuel primarily gives an indication of which safety-related characteristic?

Accepted Answer

Introduction: Flash point is the lowest temperature at which a liquid emits sufficient vapour to form an ignitable mixture with air near the surface. It is a key safety index for handling and storage of petroleum fuels. Given Data / Assumptions: Standard closed-cup/ open-cup test methods are implied. We compare flash point to other properties like volatility curves or phase diagrams. Concept / Approach: Flash point addresses ignition/fire/explosion hazard by indicating the ease with which vapours can ignite. While more volatile liquids often have lower flash points, “flash point” is not a direct measure of the full distillation volatility or the detailed boiling behaviour. It is a safety indicator rather than a thermodynamic phase-diagram descriptor. Step-by-Step Solution: Identify what flash point directly reflects: ignition risk of vapours in air.Eliminate properties it does not directly quantify: distillation volatility curves and boiling point diagrams.Choose the option that states the safety hazard aspect. Verification / Alternative check: Fuel specifications classify storage and handling categories by flash point thresholds because they track flammability risk during routine operations. Why Other Options Are Wrong: Volatility under distillation: Related but not directly given by flash point; distillation tests (e.g., ASTM D86) address volatility. Boiling point diagram: Flash point does not describe phase-equilibrium curves. All (a), (b), (c): Overbroad; only (b) captures the essence. Storage tank corrosion tendency: Not measured by flash point. Common Pitfalls: Assuming a numerical correlation between flash point and the entire volatility profile; they are distinct tests. Final Answer: Explosion hazards characteristics (ignition risk of vapours)

Question 15

Catalytic reforming (Platforming) configuration: In modern practice, UOP Platforming units commonly employ which reactor/catalyst handling configuration?

Accepted Answer

Introduction: Platforming is UOP’s catalytic reforming technology to upgrade naphtha into high-octane reformate and hydrogen. Reactor configuration and how the catalyst is regenerated affect uptime and severity. Given Data / Assumptions: Feed: desulphurised straight-run naphtha. Catalyst: platinum (and bi/tri-metallic) on alumina. Reactor trains can be semi-regenerative or continuous catalyst regeneration (CCR). Concept / Approach: Historically, semi-regenerative fixed-bed units required periodic shutdowns for regeneration. Modern CCR Platforming uses a moving-bed system that continuously circulates catalyst to a regenerator, enabling higher severity, stable octane, and longer on-stream times. Thus, “moving bed” best describes the prevalent contemporary configuration. Step-by-Step Solution: Identify modern standard: CCR Platforming.Note that CCR relies on a moving bed of catalyst moving slowly through reactors to the regenerator.Select “Moving bed.” Verification / Alternative check: Refinery process summaries distinguish semi-regenerative (fixed-bed) versus CCR (moving-bed). Many new installations are CCR for performance and economics. Why Other Options Are Wrong: Fluidised bed: Not the standard for reforming (FCC uses fluidisation). Non-regenerative fixed bed only: Outdated as a blanket statement; many units are CCR. Regenerative without moving catalyst: CCR regeneration involves catalyst movement. Batch stirred tank: Not applicable. Common Pitfalls: Confusing FCC fluidised-bed concepts with reforming; ignoring the evolution from semi-regenerative to CCR moving-bed units. Final Answer: Moving bed

Question 16

Octane number reference compound: Iso-octane is used as the 100-point reference for octane number. Its correct chemical name is:

Accepted Answer

Introduction: Octane number compares gasoline knock resistance to a reference blend of iso-octane (defined as 100) and n-heptane (defined as 0). The question asks for the correct chemical name of iso-octane. Given Data / Assumptions: Standard octane definition is implied. Concept / Approach: Iso-octane is the branched paraffin 2,2,4-trimethylpentane. Its high knock resistance under spark-ignition conditions makes it the 100 reference point. Step-by-Step Solution: Recall the definition of octane number.Match “iso-octane” to its IUPAC name: 2,2,4-trimethylpentane.Eliminate other compounds which are unrelated or unsaturated/aromatic. Verification / Alternative check: Fuel property tables list iso-octane explicitly as 2,2,4-trimethylpentane. Why Other Options Are Wrong: α-methyl naphthalene: Aromatic; historical cetane reference, not octane. 1,3-butadiene / Tetramethylethylene: Olefins, not the octane standard. 3-ethylhexane: Another isomer, not the octane reference. Common Pitfalls: Mixing up octane and cetane reference compounds. Final Answer: 2,2,4-trimethylpentane

Question 17

Desalter corrosion risk: Which chloride salt impurity in crude petroleum most prolifically generates HCl during heating/distillation, causing overhead corrosion if not removed?

Accepted Answer

Introduction: Chloride salts carried with crude (as brine) hydrolyse during heating, forming HCl that can attack overhead systems in the crude/vacuum distillation units. Understanding which salts are most problematic informs desalter performance targets. Given Data / Assumptions: Common brine salts: NaCl, MgCl2, CaCl2, KCl. Distillation preheat and furnace conditions promote hydrolysis. Concept / Approach: MgCl2 hydrolyses more readily than NaCl at typical preheat temperatures, liberating HCl earlier and in larger amounts, which raises corrosion and ammonium chloride salt fouling risks in overhead systems. Therefore, magnesium chloride is the most prolific HCl source if not adequately removed by desalting/washing. Step-by-Step Solution: Compare hydrolysis tendencies: MgCl2 > CaCl2 > NaCl under typical conditions.Identify the salt most associated with overhead HCl formation: magnesium chloride.Select “Magnesium.” Verification / Alternative check: Corrosion control guidelines highlight MgCl2 as the key driver of HCl formation prior to top tower neutralisation. Why Other Options Are Wrong: Sodium / Potassium: Chlorides hydrolyse less under the same conditions. Calcium: Hydrolyses, but typically less prolific than magnesium under crude preheat ranges. Iron: Not a chloride brine constituent for this context. Common Pitfalls: Assuming all chlorides behave identically; hydrolysis kinetics differ significantly. Final Answer: Magnesium

Question 18

Fuel sweetening in refining: In petroleum product treatment, “sweetening” primarily refers to the removal or conversion of which species?

Accepted Answer

Introduction: “Sweet” petroleum products are low in sulphur and mercaptans, with reduced odour and corrosivity. Processes include mercaptan oxidation (Merox) or hydrotreating to convert/remove sulphur species. Given Data / Assumptions: Scope: finished product treating. Goal: odour reduction, improved stability/corrosion performance. Concept / Approach: Sweetening targets sulphur-bearing compounds. Merox oxidises mercaptans to disulfides (less odorous), while hydrotreating removes sulphur as H2S. Hence, “sweetening” refers to sulphur compound removal/conversion. Step-by-Step Solution: Identify key contaminants: mercaptans/sulphur species.Match to product “sweetness.”Select the option explicitly naming sulphur/mercaptans. Verification / Alternative check: Product specifications (e.g., mercaptan sulphur limits) define “sweet.” Why Other Options Are Wrong: Water: Removed by drying, not sweetening. Organic particulates/wax/asphaltenes: Other treatments handle these. Common Pitfalls: Equating dehydration or filtration with sweetening. Final Answer: Sulphur and its odorous compounds (e.g., mercaptans)

Question 19

Sulphur determination in crude oil: Which method is classically regarded as the best laboratory approach for determining total sulphur in crude oil?

Accepted Answer

Introduction: Total sulphur in crude oil is a critical quality parameter affecting corrosion, emissions, and downstream processing. Several classical lab techniques exist, but only specific ones target sulphur directly. Given Data / Assumptions: We compare general organic analysis methods vs energy calorimetry vs sulphur-specific combustion methods. Concept / Approach: Kjeldahl and Dumas are primarily for nitrogen determination (Kjeldahl for NH3 from organic N; Dumas for N by combustion). A bomb method can burn the sample in oxygen; combustion gases (SO2/SO3) are absorbed and analysed to quantify sulphur. While modern refineries use e.g., XRF or UV fluorescence, the classical best answer among the listed options is the bomb method associated with bomb calorimeter apparatus and post-combustion sulphur analysis. Step-by-Step Solution: Eliminate nitrogen methods (Kjeldahl, Dumas) and calorimeters for heating value only (Junkar's).Identify the combustion-in-oxygen bomb method with gas absorption as the sulphur determination route.Select option (c). Verification / Alternative check: Classical analytical chemistry texts describe sulphur determination by oxygen-bomb combustion with subsequent titration or instrumental detection of absorbed sulphur oxides. Why Other Options Are Wrong: Kjeldahl/Dumas: Nitrogen, not sulphur. Junkar's calorimeter: Measures calorific value of gas; not a sulphur test. Hydrometer: Density only; cannot give total sulphur. Common Pitfalls: Assuming any calorimeter implies sulphur analysis; only dedicated bomb combustion with absorption and analysis yields sulphur content. Final Answer: Bomb calorimeter (bomb method with absorption of combustion gases)

Question 20

Hydrogen-to-carbon ratio by weight: Among these refinery streams, which typically has the maximum H/C ratio by weight?

Accepted Answer

Introduction: The hydrogen-to-carbon ratio (by weight) increases as hydrocarbons become lighter and more paraffinic. This metric correlates with cleaner combustion and higher mass-based heating value. Given Data / Assumptions: Compare representative refinery streams from light to heavy. Assume typical crude slate and standard boiling ranges. Concept / Approach: Lighter fractions (e.g., naphtha) have higher hydrogen content relative to carbon than heavier, more aromatic/asphaltenic fractions (diesel, fuel oil, residues). Therefore, naphtha shows the highest H/C by weight among the listed options. Step-by-Step Solution: Order streams by typical aromaticity/heaviness: naphtha < gasoline < diesel < fuel oil < residue (heaviest).Recognise lighter streams are more paraffinic → higher H/C.Select “Naphtha.” Verification / Alternative check: Assay data and hydrogen balance calculations reflect rising H/C with lighter cuts. Why Other Options Are Wrong: Gasoline: Slightly heavier/more aromatic than light naphtha on average. Diesel / Fuel oil / Residue: Progressively heavier and more carbon-rich. Common Pitfalls: Confusing volumetric energy density trends with H/C ratio trends. Final Answer: Naphtha

Petroleum Refinery Engineering Questions