Petroleum & Petrochemicals Interview Questions

Crude oil is a naturally occurring mixture of hydrocarbons found in underground reservoirs. Main components: Paraffins (alkanes) - straight or branched chain saturated hydrocarbons (CnH2n+2), typically 15-60% of crude. Naphthenes (cycloalkanes) - ring-structured saturated hydrocarbons, 30-60%. Aromatics - ring structures with conjugated double bonds (benzene derivatives), 3-30%. Also contains: sulfur compounds (mercaptans, sulfides, thiophenes), nitrogen compounds, oxygen compounds, and metals (V, Ni, Fe). Composition varies by source - light crudes have more paraffins, heavy crudes more aromatics and metals. API gravity classifies crude: light (>31 API), medium (22-31), heavy (<22).

Atmospheric distillation (crude distillation unit, CDU) is the primary separation process in a refinery. Crude oil is heated to about 350-400C and fed to a fractionating column operating at near-atmospheric pressure. Products from top to bottom: LPG (C3-C4, <30C), light naphtha (C5-C6, 30-90C), heavy naphtha (C6-C12, 90-180C), kerosene (C10-C16, 180-250C), diesel/gas oil (C14-C20, 250-350C), and atmospheric residue (>350C, sent to vacuum unit). Separation is based on boiling point differences. Typical capacity: 100,000-400,000 barrels per day. CDU is the first major processing unit; all other refinery processes receive feeds from CDU cuts.

Vacuum distillation is needed because atmospheric residue cannot be heated above 350-400C without thermal cracking (decomposition). Operating under vacuum (25-100 mmHg) lowers boiling points, allowing further separation without cracking. Products: Light vacuum gas oil (LVGO, 350-450C), heavy vacuum gas oil (HVGO, 450-550C), and vacuum residue (>550C). LVGO and HVGO are feeds for conversion units (FCC, hydrocracker). Vacuum residue goes to coker, visbreaker, or asphalt production. Vacuum is maintained by steam ejectors. Column has large diameter due to high vapor volume at low pressure. Packing often used instead of trays to minimize pressure drop.

Fluid catalytic cracking (FCC) is a key conversion process that cracks heavy gas oil into lighter, more valuable products like gasoline and LPG. Uses zeolite catalyst in a fluidized bed. Reaction at 480-540C, near atmospheric pressure. Products: cracked naphtha (gasoline component), LPG (propylene for petrochemicals), light cycle oil (diesel blending), heavy cycle oil, and coke (deposited on catalyst). Catalyst continuously circulates between reactor and regenerator where coke is burned off. FCC is important because it converts low-value heavy fractions to high-value gasoline and petrochemical feedstocks. Refinery profitability often depends heavily on FCC performance.

Hydrocracking cracks heavy hydrocarbons in the presence of hydrogen and catalyst. Operating conditions: 350-450C, high pressure (100-200 bar), with bifunctional catalyst (acid and metal functions). Products: naphtha, jet fuel, diesel - high quality with low sulfur and aromatics. Differences from FCC: higher hydrogen consumption but better product quality, more flexible feed processing (can handle poor quality feeds), produces more middle distillates (jet, diesel) vs. gasoline, operates at high pressure with hydrogen, no coke production (hydrogen prevents coking). Hydrocracking is preferred when maximizing diesel/jet production and processing heavy or high-sulfur feeds. Higher capital and operating cost than FCC.

Hydrotreating uses hydrogen to remove sulfur, nitrogen, and metals from petroleum fractions without significantly cracking the molecules. Sulfur forms H2S, nitrogen forms NH3. Operating conditions: 300-400C, 30-100 bar hydrogen pressure, over Co-Mo or Ni-Mo catalyst on alumina support. Also saturates olefins and some aromatics. Necessary because: environmental regulations limit sulfur in fuels (diesel <10 ppm), sulfur poisons downstream catalysts (FCC, reformer), nitrogen and metals also harm catalysts, and product stability improves. Different units for different feeds: naphtha hydrotreater, kerosene hydrotreater, diesel hydrotreater, VGO hydrotreater. Each optimized for feed characteristics and product requirements.

Catalytic reforming converts low-octane naphtha to high-octane reformate for gasoline blending. Also produces hydrogen as a byproduct. Reactions: dehydrogenation of naphthenes to aromatics (main reaction), isomerization, dehydrocyclization of paraffins. Operating conditions: 480-530C, 10-35 bar, over Pt-based catalyst on acidic alumina. Products: reformate (high octane, 95-100 RON) rich in aromatics (benzene, toluene, xylene), hydrogen (valuable for hydrotreating), and LPG. Modern refineries use continuous catalyst regeneration (CCR) reformers. Reformate can also be separated to produce BTX for petrochemical use. Hydrogen production makes reformer integral to refinery hydrogen balance.

Ethylene is produced primarily by steam cracking of hydrocarbons (ethane, naphtha, or gas oil) at 750-900C with steam dilution and very short residence time (milliseconds). Products: ethylene (main), propylene, butadiene, aromatics, and fuel gas. Naphtha cracking produces more byproducts; ethane cracking is more selective to ethylene. Ethylene is the most important petrochemical because it is the building block for: polyethylene (largest volume plastic), ethylene oxide/glycol (antifreeze, PET), styrene, vinyl chloride (PVC), and many other chemicals. Global ethylene capacity exceeds 200 million tons/year. Ethylene plant (cracker) is typically the centerpiece of a petrochemical complex.

Polyethylene (PE) is the most widely produced plastic. Main types: LDPE (Low Density) - branched structure, flexible, used for films, bags, squeeze bottles, wire insulation. LLDPE (Linear Low Density) - linear with short branches, tougher than LDPE, used for stretch films, liners. HDPE (High Density) - linear structure, rigid, strong, used for bottles, pipes, containers, drums. UHMWPE (Ultra High Molecular Weight) - very high strength, wear resistant, used for bearings, medical implants. Production: LDPE by high-pressure free radical polymerization (1000-3000 bar), HDPE and LLDPE by catalytic polymerization (Ziegler-Natta or metallocene catalysts) at lower pressures. Properties depend on density, molecular weight, and branching.

Ammonia is produced by the Haber-Bosch process: N2 + 3H2 = 2NH3. Process steps: (1) Hydrogen production - steam reforming of natural gas (CH4 + H2O = CO + 3H2) followed by water-gas shift (CO + H2O = CO2 + H2). (2) Air separation for nitrogen. (3) Syngas purification - remove CO2 and CO. (4) Synthesis - over iron catalyst promoted with K2O and Al2O3, at 400-500C and 150-300 bar. Equilibrium favors products at low temperature and high pressure. Single-pass conversion is 15-25%; unreacted gas is recycled. Ammonia condensed from product stream. Major use: fertilizers (urea, ammonium nitrate, DAP). Also for explosives, plastics, and industrial chemicals. Large-scale plants produce 1000-3000 tons/day.

Urea is produced by reacting ammonia with carbon dioxide in two steps: (1) Carbamate formation: 2NH3 + CO2 = NH2COONH4 (fast, exothermic). (2) Dehydration: NH2COONH4 = NH2CONH2 + H2O (slow, endothermic, equilibrium limited). Conditions: 180-210C, 150-250 bar. Overall conversion about 60-70%; unreacted ammonia and CO2 are recovered and recycled. Modern plants use stripping technology for efficient recovery. Final steps: concentration by evaporation, prilling or granulation for solid product. Urea is the most important nitrogen fertilizer (46% N content). Also used in: urea-formaldehyde resins, melamine production, AdBlue/DEF for diesel emission control. Production integrated with ammonia plant for CO2 supply.

Polypropylene (PP) is a thermoplastic polymer made from propylene monomer. Production: Ziegler-Natta or metallocene catalyst polymerization at 50-80C and 10-40 bar. Key properties: low density (0.90-0.91 g/cm3), high stiffness, good chemical resistance, excellent fatigue resistance (living hinge applications), higher melting point than PE (160-170C). Types: homopolymer (rigid), random copolymer (with ethylene, more flexible), and impact copolymer (contains rubber phase for toughness). Applications: automotive parts, packaging, textiles (fibers), furniture, medical devices, pipes. Second largest volume plastic after polyethylene. Global production exceeds 75 million tons/year.

Octane number measures a fuel's resistance to knock (premature ignition) in spark-ignition engines. Reference scale: n-heptane = 0 (knocks easily), iso-octane (2,2,4-trimethylpentane) = 100 (knock resistant). Two measurements: RON (Research Octane Number) - moderate conditions, and MON (Motor Octane Number) - severe conditions. Pump octane (USA) = (RON + MON)/2. Higher octane fuels can use higher compression ratios for better efficiency. Octane boosters: aromatics (high octane), branched paraffins (high octane), straight-chain paraffins (low octane), olefins (moderate). Refinery processes to increase octane: reforming, isomerization, alkylation. Previously tetraethyl lead was used as octane booster, now phased out.

Crude desalting removes salt, water, and sediment before distillation. Salt causes: corrosion in distillation towers (especially from HCl formed from MgCl2 and CaCl2), fouling of heat exchangers, and catalyst poisoning in downstream units. Process: crude is mixed with wash water (3-10% volume), passed through mixing valve or static mixer to form emulsion, then separated in electrostatic desalters (electric field breaks emulsion, water/salt settles). Operating conditions: 100-150C, 5-15 bar. Two-stage desalting achieves 90-95% salt removal. Key parameters: temperature, water injection rate, mixing intensity, and electrical field strength. Brine water is treated before disposal. Essential first step in all refineries.

Refinery emissions include: Air emissions - SO2 (from sulfur in fuel and flare), NOx (from combustion), CO2 (greenhouse gas from combustion), VOCs (volatile organic compounds from storage and fugitives), particulates (from FCC regenerator and combustion). Water emissions - oily water, dissolved hydrocarbons, sulfides, ammonia, phenols. Solid waste - spent catalyst, tank bottoms, sludge. Emission controls: sulfur recovery units (Claus process) to minimize SO2, selective catalytic reduction for NOx, vapor recovery from tanks, wastewater treatment plants, and flare gas recovery systems. Refineries must meet increasingly stringent environmental regulations. Environmental management is a major operational focus.

A crude assay provides detailed composition and property data. Key information: API gravity and sulfur content (overall quality indicators), TBP distillation curve (yield of each cut), sulfur distribution by cut, nitrogen and metals content (catalyst deactivation potential), naphtha properties (naphthenes content for reformer feed), middle distillate quality (cetane, pour point, sulfur), vacuum gas oil properties (CCR, metals for FCC/hydrocracker feed), and residue quality (carbon residue, metals for coker/visbreaker). Using assay data: determine product yields at different cut points, estimate utility consumption, evaluate processing difficulty, and calculate refining margins. Compare assays to select crudes that maximize margin given refinery configuration and product requirements.

FCC yield optimization: Temperature - higher riser temperature increases conversion and gas/LPG yield but reduces liquid yield; typical range 510-540C. Catalyst/oil ratio - higher C/O increases conversion and gasoline selectivity. Catalyst activity - fresh catalyst activity optimized for selectivity vs. coke make. Feed quality - higher CCR and metals in feed increase coke and gas, reduce liquid yield. Feed temperature - higher preheat reduces coke and increases conversion. Steam injection - affects contact time and selectivity. Catalyst type - different zeolites give different gasoline/LPG split. Product value drives optimization - maximize gasoline or maximize propylene depending on economics. Operating constraints: regenerator temperature, air blower capacity, wet gas compressor capacity, and product quality specifications.

Hydrocracker operating modes: Mild hydrocracking - lower severity, 30-50% conversion, produces some unconverted oil for FCC feed. Full conversion - 95-100% conversion per pass, no unconverted oil. Once-through - single pass, no recycle of unconverted material. Recycle operation - unconverted oil recycled to extinction. Product slate flexibility: Naphtha mode - maximize gasoline production (higher temperature). Middle distillate mode - maximize jet/diesel (moderate temperature). Flexibility achieved by adjusting temperature, catalyst activity, and recycle ratio. Two-stage designs: first stage for hydrotreating and partial conversion, second stage for finishing conversion. Single-stage designs are simpler but less flexible. Mode selection based on product value, crude slate, and seasonal demand.

Claus process converts H2S to elemental sulfur in two steps: (1) Thermal stage - partial combustion of H2S: H2S + 1.5O2 = SO2 + H2O at 1000-1400C in furnace. Produces 60-70% of sulfur. (2) Catalytic stages - H2S + SO2 = S + H2O over alumina catalyst at decreasing temperatures (300C, 240C, 200C in successive stages). Each stage followed by condenser to remove sulfur. Overall: 2H2S + SO2 = 3S + 2H2O. Standard 3-stage Claus achieves 95-97% recovery. Tail gas treatment (SCOT, Beavon) reaches 99.9%. Feed gas from amine regeneration. Air flow controls H2S/SO2 ratio (critical 2:1). COS and CS2 hydrolyzed in first catalyst bed. Sulfur product is liquid, sold or stored in solid form.

Both convert vacuum residue to lighter products and coke. Delayed coking: batch operation in drums, feed enters at 480-500C, remains in drum 16-24 hours as coking proceeds, coke cut from drum with water jets. Produces: naphtha, gas oil, and 20-30% coke. Coke can be fuel grade or anode grade (low metals/sulfur). Fluid coking: continuous fluidized bed operation at 510-540C, shorter residence time. Coke particles circulate between reactor and burner (heats incoming coke). Higher liquid yield than delayed coking (5-10% more). Flexicoking adds gasifier to convert coke to fuel gas. Selection: delayed coking more common (lower capital, simpler), fluid coking for high conversion requirements or when coke has low value.

Cracking severity measures the extent of thermal decomposition, typically expressed as COT (coil outlet temperature) or conversion to methane/propylene. Higher severity: more ethylene production, more methane and hydrogen, less propylene and C4s, more aromatics in pyrolysis gasoline. Lower severity: more propylene and C4 olefins, less ethylene, better yields of liquid products. Severity selection based on feedstock (ethane needs higher severity than naphtha) and desired product slate (maximize ethylene vs. maximize C3/C4). Typical COT: 800-850C for naphtha, 850-900C for ethane. Residence time is very short (100-500 ms). Severity also affects coking rate - higher severity increases tube coking, requiring more frequent decoking. Optimize for product value minus operating costs.

Propylene production routes: Steam cracking of naphtha - co-product with ethylene, accounts for ~55% of supply. FCC - significant propylene from gasoline cracking, ~30% of supply; can be enhanced with ZSM-5 additive. Propane dehydrogenation (PDH) - catalytic (Cr/Al2O3 or Pt-Sn), growing rapidly due to shale gas propane availability. Metathesis - ethylene + butenes = propylene over W or Re catalyst. Methanol to propylene (MTP) - emerging route using coal-based methanol in China. Selection factors: feedstock availability and cost, integration with existing facilities, capital cost, and product purity requirements. PDH produces polymer-grade propylene directly; FCC propylene requires upgrading for polymer use. Global propylene demand growing faster than ethylene.

Solution polymerization - polymer dissolves in solvent, good heat transfer, used for EPDM, some LDPE. Slurry (suspension) - polymer as solid particles in diluent (hexane), good temperature control, used for HDPE, PP; requires polymer/diluent separation. Gas phase - polymer forms on catalyst in fluidized bed of polymer particles, no solvent, simpler recovery, used for HDPE, LLDPE, PP. High pressure - liquid phase at 1000-3000 bar, free radical mechanism, used for LDPE; distinctive branched structure. Selection factors: polymer type and properties, economics (solvent handling costs), heat removal capability, and flexibility. Many modern plants use gas phase (Unipol, Innovene) or slurry loop (Chevron Phillips) for simplicity and environmental benefits.

BTX (benzene, toluene, xylenes) extraction from reformate or pyrolysis gasoline: Extraction - uses polar solvents (sulfolane, NMP, tetraethylene glycol) to separate aromatics from non-aromatics based on solubility difference. Extract contains aromatics, raffinate contains non-aromatics. Separation - extractive distillation or liquid-liquid extraction. BTX fractionation - series of columns: benzene column (benzene overhead), toluene column (toluene overhead), xylene column (mixed xylenes to isomers unit). Xylene isomers separation: para-xylene by adsorption (Parex process) or crystallization, ortho-xylene by distillation, meta-xylene by isomerization. Para-xylene most valuable (PTA for PET). Toluene can be converted to benzene or xylenes by disproportionation/transalkylation.

Isomerization converts straight-chain paraffins to branched isomers for octane improvement. Light naphtha isomerization: C5/C6 fraction over Pt/chlorided alumina or zeolite catalyst at 120-180C, 20-35 bar hydrogen. n-pentane (62 RON) converts to isopentane (92 RON), n-hexane (25 RON) to 2,2-dimethylbutane (92 RON). Process configurations: once-through, recycle of unconverted n-paraffins (DIH, DIP), or integration with molecular sieves for normal paraffin recycle. Butane isomerization converts n-butane to isobutane for alkylation feed. C5/C6 isomerization typically achieves product octane of 82-92 RON depending on configuration. Important because regulations limit benzene in gasoline, so benzene precursors must be hydrogenated and octane recovered via isomerization.

Alkylation combines isobutane with light olefins (propylene, butylene) to produce high-octane branched paraffins (alkylate) for gasoline blending. Acid catalysts: HF (hydrofluoric acid) or H2SO4 (sulfuric acid). Reaction: isobutane + butene = isooctane (2,2,4-trimethylpentane, 100 RON). Conditions: 5-40C (low temperature favors product quality), high isobutane/olefin ratio (5-15:1 external), intimate mixing. Products: alkylate (94-98 RON), n-butane, propane. HF process: liquid HF catalyst, continuous, compact, but HF hazard concern. H2SO4 process: requires continuous acid refresh, larger equipment. Newer solid acid catalysts being developed. Alkylate is premium gasoline component - no sulfur, no aromatics, no olefins, high octane.

Hydrogen balance matches supply with demand. Supply sources: catalytic reformer (main source, ~60%), steam methane reforming (SMR) units, electrolysis (emerging). Demand: hydrotreaters (largest consumer), hydrocracker, other hydroprocessing. Balance management: reformer severity affects hydrogen yield, import hydrogen from merchant suppliers if deficit, export excess (rare). Quality considerations: reformer hydrogen contains light hydrocarbons, requires purification (PSA) for sensitive consumers like hydrocracker. Network optimization: cascade hydrogen from high-purity to lower-purity users, recover hydrogen from purge streams, compress and recycle where economic. Increasing clean fuel requirements have raised hydrogen demand significantly. Many refineries now hydrogen-limited, requiring SMR or imports.

PVC (polyvinyl chloride) production: VCM synthesis - ethylene + Cl2 = EDC (direct chlorination) or ethylene + HCl + O2 = EDC (oxychlorination); EDC cracked to VCM + HCl at 500C. VCM polymerization - suspension (most common), emulsion, or bulk process; free radical initiation at 40-60C. Suspension PVC: porosity controlled by reaction conditions, absorbs plasticizers well. Products: rigid PVC - pipes, profiles, windows (no plasticizer, 60% of market); flexible PVC - cables, flooring, films (with phthalate or non-phthalate plasticizers). Key properties: good chemical resistance, durability, flame resistance (Cl content), low cost. Environmental considerations: chlorine content, plasticizer migration, disposal/recycling challenges. Global capacity ~50 million tons/year.

Methanol applications: Formaldehyde production (~35%) - for resins, adhesives, plastics. MTBE/MTAE (~15%) - gasoline oxygenate/octane booster. Acetic acid (~10%) - carbonylation of methanol. DME (dimethyl ether) - fuel, aerosol propellant. Olefins (MTO/MTP) - methanol to ethylene/propylene, growing in China. Biodiesel - transesterification of fats. Fuel - direct blending in gasoline (M85, M100), fuel cells. Chemical intermediate - for chloromethanes, methylamines, MMA. Production: synthesis gas (CO + H2) over Cu/ZnO/Al2O3 catalyst at 250C, 50-100 bar. Largest merchant chemical by volume (~100 million tons/year). Coal-based methanol significant in China (coal-to-chemicals routes).

Ethylene oxide (EO) production: direct oxidation of ethylene with oxygen over silver catalyst at 250-280C, 10-25 bar: C2H4 + 0.5O2 = EO. Selectivity ~80%; side reactions produce CO2 and water. EO is highly reactive intermediate. Ethylene glycol (EG) production: EO hydration with water at 150-200C, 15-20 bar: EO + H2O = MEG. Higher glycols (DEG, TEG) formed with excess EO. Water/EO ratio controls product distribution. Separation by vacuum distillation. Applications: MEG (~70% of EO) - polyester fiber and PET, automotive antifreeze. EO also used for: ethoxylates (surfactants), ethanolamines, glycol ethers. Large-scale plants produce 500,000-1,000,000 tons/year MEG equivalent.

Reformer catalyst factors: Feedstock quality - sulfur poisons Pt (must be <0.5 ppm), nitrogen and metals also harmful, naphthenes content determines hydrogen and aromatics yield. Operating conditions - temperature (activity vs. selectivity), pressure (lower favors aromatics but increases coking), H2/HC ratio (suppresses coking). Catalyst type - Pt on acidic alumina, promoted with Re or Sn for stability, chloride for acidity. Deactivation mechanisms: coking (reversible by regeneration), metal sintering (irreversible at high temperature), poisoning (permanent). Regeneration: semi-regenerative (shutdown every 6-24 months), cyclic (swing reactors), CCR (continuous catalyst movement and regeneration). Catalyst life: 3-7 years for CCR, shorter for fixed bed. Performance monitoring: octane, hydrogen purity, and coke make.

ULSD specifications: Sulfur - max 10-15 ppm (Euro V/VI, US). Cetane number - minimum 51 (Europe), 40 (US), higher is better ignition quality. Density - 820-845 kg/m3, affects energy content. Flash point - minimum 55C for safety. Viscosity - 2-4.5 cSt at 40C for injection system. Cloud point/CFPP - climate dependent, cold flow properties. Lubricity - HFRR <460 microns, may need additives. Aromatics - polycyclic aromatics limited for emissions. Stability - oxidation stability for storage. Achieving ULSD: deep hydrotreating at high severity, may require two-stage treating for difficult feeds. Specifications increasingly stringent - Euro 7 will add further restrictions on aromatic content and other properties affecting emissions.

Phosphate fertilizer production: Phosphate rock mining - apatite (Ca5(PO4)3F) is primary source. Phosphoric acid production - wet process: rock + H2SO4 = H3PO4 + CaSO4 (gypsum byproduct). DAP (diammonium phosphate) - neutralize phosphoric acid with ammonia: H3PO4 + 2NH3 = (NH4)2HPO4. Contains 18% N, 46% P2O5. MAP (monoammonium phosphate) - H3PO4 + NH3 = NH4H2PO4. Contains 11% N, 52% P2O5. TSP (triple superphosphate) - rock + H3PO4 = Ca(H2PO4)2. Contains 46% P2O5, no nitrogen. NPK compounds - blend or chemical combination of N, P, K sources. Environmental issues: gypsum disposal, fluorine emissions, heavy metals in rock. Process optimization focuses on P2O5 recovery and grade.

Refinery wastewater treatment: Primary treatment - API separator removes free oil by gravity (density difference), CPI (corrugated plate interceptor) for improved separation, dissolved air flotation (DAF) for emulsified oil. Secondary treatment - biological treatment using activated sludge or fixed film to remove dissolved organics (BOD, COD), phenols, and ammonia. May need equalization for shock loads. Tertiary treatment - sand filtration for suspended solids, activated carbon for residual organics, membrane processes for reuse quality. Sour water stripping - removes H2S and NH3 from sour water before discharge to biological treatment. Effluent limits: COD <100-150 mg/L, oil <10 mg/L, phenol <0.5 mg/L, sulfide <0.5 mg/L typically. Zero liquid discharge (ZLD) increasingly required in water-stressed regions.

Fixed bed regeneration: In-situ (reformer, hydrotreater) - controlled combustion of coke with dilute oxygen/nitrogen mixture at 400-500C, followed by redispersion and reduction. Sulfur removed by oxidation to SO2. Sequence: deoiling, coke burn, oxychlorination (reformer), reduction. Ex-situ - catalyst removed and sent to regenerator facility for severe treatment. Fluid bed (FCC): Continuous regeneration - spent catalyst flows to regenerator where coke burned with air at 650-730C, heat released heats catalyst for reactor. Two-stage regeneration: full combustion in second stage for low carbon on regenerated catalyst. Regenerator variables: temperature (higher = lower carbon but potential damage), air rate, catalyst circulation. Catalyst loss from attrition replaced by fresh catalyst addition.

Refinery LP models optimize crude selection, operations, and product slate. Structure: decision variables (crude purchases, unit rates, product sales), constraints (material balances, unit capacities, product specifications, crude contracts), and objective function (maximize margin = revenue - costs). Sub-models: crude blending, unit yields, product blending. Typical model has thousands of variables and constraints. Uses: monthly planning (crude selection, production targets), operations optimization (day-to-day adjustments), investment evaluation (what-if analysis). Shadow prices indicate value of relaxing constraints. Recursion handles nonlinear blending properties. Major tools: PIMS, RPMS, GRTMPS. LP is foundation of refinery planning; supplemented by nonlinear optimization for detailed operations and simulation for accuracy verification.

FCC kinetic models: Lumped models - 3-lump (gas oil, gasoline, gas+coke), 5-lump, 10-lump, or more. Each lump has cracking rate constant following Arrhenius temperature dependence. Reactions: primary cracking (VGO to products), secondary cracking (gasoline to gas/coke), hydrogen transfer, isomerization. Catalyst deactivation - activity decays exponentially with coke on catalyst, time-on-stream function. Yield prediction - material balances with kinetic expressions. Advanced models include: feed characterization (paraffins, naphthenes, aromatics), molecular-level simulation (structure-oriented lumping), and microactivity test (MAT) correlation. Riser hydrodynamics modeled as plug flow with catalyst slip. Parameters fitted to pilot/commercial data. Models used for yield prediction, catalyst evaluation, and unit optimization.

Deep desulfurization design: Kinetics - refractory sulfur species (dibenzothiophenes with alkyl substituents) much harder to remove than easy sulfur. Rate follows: -dC/dC = k*C^n*P_H2^m. n varies from 1 (easy sulfur) to 2 (refractory). Catalyst selection - CoMo for easy desulfurization, NiMo better for difficult feeds and denitrification, specialized catalysts for ultra-deep. Reactor design - often two stages: first stage removes bulk sulfur under milder conditions, second stage with fresh catalyst for deep removal. LHSV typically 0.5-2 hr^-1 for diesel, lower for ULSD. Hydrogen partial pressure critical - higher pressure improves kinetics and reduces coking. Temperature limited by product quality and catalyst stability. Bed grading - smaller particles at bottom for deeper desulfurization, larger at top for pressure drop control.

Metallocene catalysts are single-site catalysts with uniform active centers, producing polymers with narrow molecular weight distribution (MWD, PDI ~2) versus Ziegler-Natta's broad MWD (PDI 4-8). Metallocene advantages: precise comonomer distribution (superior copolymer properties), stereochemical control (isotactic, syndiotactic), clearer polymers (fewer catalyst residuals), and ability to make new polymer grades. Challenges: higher catalyst cost, requires methylaluminoxane (MAO) cocatalyst, sensitive to impurities, and different processing behavior (narrow MWD affects melt strength). Applications: LLDPE with unique properties (enhanced toughness, clarity), metallocene PP (better impact strength), specialty grades impossible with Z-N. Commercialized processes: ExxonMobil Exceed, Dow INSITE, Borealis Borstar. Often hybrid plants with both catalyst types for product flexibility.

SMR design considerations: Catalyst - Ni on alumina support, must resist sintering and carbon formation. Tube metallurgy - high alloy (25Cr-35Ni or higher) for 850-950C operation, stress from internal pressure and thermal expansion. Tube layout - typically 100-1000 tubes per furnace, arranged for uniform heating. Heat recovery - convection section recovers heat for steam generation, feed preheat, combustion air preheat. Steam/carbon ratio - typically 2.5-4, higher prevents coking but reduces efficiency. Operating pressure - higher pressure reduces compressor cost but shifts equilibrium unfavorably. Fired duty distribution - top-fired, side-fired, or terrace-fired designs. Reliability factors: tube inspection, catalyst replacement every 3-5 years, burner maintenance. Efficiency typically 65-80% (LHV basis). CO2 capture increasingly incorporated.

Crude compatibility assessment: Incompatibility causes - asphaltenes precipitation when mixing crudes with different solvent power. Mechanism - asphaltenes are stabilized by resins; paraffinic crudes (high SBN/saturates) can precipitate asphaltenes from heavy crudes. Tests: spot test (drop of crude on filter paper, look for ring), colloidal instability index (CII = saturates + asphaltenes)/(resins + aromatics), p-value (peptization value), and hot filtration test. Compatibility mapping - test all pairs of crudes in planned blend ratios. Consequences of incompatibility: fouling in preheat train, filter plugging, furnace tube coking, product instability. Mitigation: blend incompatible crudes at lower ratios, add aromatic flux, or process separately. Compatibility is critical for opportunity crude processing where diverse crudes are economically attractive.

Gasification technologies: Entrained flow (Shell, GE, Siemens) - high temperature (1300-1500C), feed as slurry or dry powder, short residence time, slagging operation, produces clean syngas, suitable for any feed. Fixed/moving bed (Lurgi, BGL) - lower temperature (600-1200C), lump feed, longer residence time, produces methane and tars requiring cleanup. Fluidized bed (HTW, KBR) - moderate temperature (900-1100C), handles fine particles, better heat transfer. Selection factors: feed characteristics (coal rank, ash properties), syngas application (hydrogen, power, chemicals), scale, and capital cost. Entrained flow dominates for large-scale chemical production (cleaner syngas). Gasification enables coal/petcoke to chemicals, integrated gasification combined cycle (IGCC) for power, and carbon capture. Syngas composition varies: H2/CO ratio adjusted by water-gas shift for downstream application.

Runaway protection design: Hazard identification - exothermic polymerization can accelerate uncontrollably with temperature (Arrhenius kinetics). Heat balance - ensure cooling capacity exceeds maximum heat generation at all conditions. Detection systems - multiple independent temperature measurements, rate-of-rise monitoring, pressure monitoring for gas evolution. Automatic responses - staged based on severity: reduce feed rate, increase cooling, inject inhibitor/kill agent, emergency depressurization. Inhibitor systems - shortstop agents (hydroquinone, MEHQ) injected rapidly to terminate reaction. Mechanical design - vessels rated for emergency pressure, relief systems sized for runaway, containment for release. Process design - limit inventory, use continuous rather than batch where possible, implement proper mixing. Safety studies - reaction calorimetry (ARC, RC1) to characterize runaway kinetics, HAZOP, LOPA to verify protection adequacy.

Process intensification (PI) applications: Reactive distillation - combines reaction and separation in one unit (MTBE, TAME production), eliminates equilibrium limitation, reduces equipment and energy. Dividing wall columns - single shell for multiple separations, 30% energy savings, more complex control. Microreactors - enhanced heat/mass transfer for fast, exothermic reactions (e.g., nitration), improved safety through small inventory. Spinning disc reactors - thin films, millisecond residence times for precipitation, polymerization. Membrane reactors - combine reaction with selective removal (hydrogen production with Pd membrane). Heat-integrated reactors - use reaction heat directly for separation or preheating. Benefits: smaller equipment, lower energy consumption, improved safety (smaller inventory), and better product quality. Challenges: scale-up, control complexity, and limited operating flexibility. PI enables economically viable small-scale plants.

Residue upgrading evaluation: Technologies - delayed coking (lowest capital, produces coke), fluid coking/Flexicoking (higher conversion, uses coke), residue hydrocracking (highest quality products, high hydrogen consumption), solvent deasphalting (produces deasphalted oil for FCC/hydrocracker). Economic factors: Capital cost - hydrocracking highest, coking lowest. Operating cost - hydrogen cost dominates for hydrocracking, energy for coking. Product value - hydrocracker produces higher-value products. Yield structure - analyze liquid yields and product quality. Byproduct value - coke value varies widely (fuel grade vs. anode grade), DAO value depends on downstream processing. Integration - hydrogen balance, heat integration, shared infrastructure. Evaluation approach: model each option in refinery LP, compare NPV/IRR including implementation timeline. Location factors: coke market, hydrogen cost, environmental constraints. Heavy-sour crude discounts drive residue upgrading investments.

Carbon capture options: Post-combustion - amine absorption of CO2 from flue gas, applicable to heaters/boilers/FCC regenerator. Energy penalty 15-30% for regeneration. Pre-combustion - capture CO2 from syngas before combustion, applicable to hydrogen plants. Shift reaction converts CO to CO2 for easier capture. Oxyfuel - combust in pure oxygen, producing concentrated CO2 stream. High capital for air separation unit. Point source capture - prioritize high-concentration streams (hydrogen plant, ammonia plant) for lowest cost. CO2 utilization - enhanced oil recovery, chemicals production (urea, methanol, carbonates). Storage - geological sequestration in depleted reservoirs or saline aquifers. Economics - capture cost $40-100/ton CO2 depending on source concentration. Regulatory drivers - carbon pricing, emission limits. Many refiners focusing on hydrogen production decarbonization (blue hydrogen) as first step.

Gas-phase reactor modeling components: Population balance - track particle size distribution as polymer grows on catalyst. Kinetics - propagation, chain transfer, termination rates following monomer, comonomer, and hydrogen concentrations. Mass balance - monomer consumption, inert buildup, gas composition. Energy balance - heat removal by circulating gas, residence time distribution effects. Fluidization - minimum fluidization velocity, bubble dynamics, particle mixing. Heat transfer - particle-to-gas, gas-to-wall, bed-to-cooling coils. Model types: well-mixed CSTR approximation, two-phase (bubble-emulsion) model, CFD for detailed hydrodynamics. Key outputs: production rate, molecular weight distribution, comonomer incorporation, particle size. Control applications: grade transitions optimization, operating window determination. Validation against plant data essential - parameters fitted to pilot and commercial operation.

Ammonia loop optimization: Conversion per pass - balance between higher conversion (lower recycle) and lower temperature (kinetics). Typically 15-25%. Inerts management - argon and methane accumulate, purge rate balances loss of valuable H2/N2 against inerts buildup. Target 10-15% inerts. Pressure - higher favors equilibrium but increases compression cost and equipment rating. Catalyst bed design - temperature profile through beds, interstage cooling (quench or indirect exchange). Multiple beds with optimal temperature trajectory. H2/N2 ratio - stoichiometric 3:1, slight excess of one compensates for preferential permeation. Separator efficiency - maximize ammonia recovery without carryover. Energy integration - use ammonia synthesis heat for feed preheat, steam generation. Advanced control - MPC for smooth operation during disturbances. Periodic analysis: catalyst activity monitoring, equipment condition, and compare actual vs. design performance.

FCC troubleshooting methodology: Symptoms analysis - low conversion, poor selectivity, high delta coke, equipment damage. Data gathering - compare current vs. baseline operation, review trends. Catalyst evaluation - activity (MAT), coke selectivity, particle size, metal content (Ni, V), physical properties. Feed analysis - CCR, metals, nitrogen, density changes. Operating conditions review - riser temperature, C/O ratio, regenerator temperature. Mechanical inspection - catalyst distribution, riser termination, cyclone performance, slide valve operation. Common problems and solutions: Low conversion - insufficient temperature, low activity catalyst, feed quality change; increase temperature or fresh catalyst addition. High coke - metal contamination, poor feed quality; passivate metals with Sb or Bi, improve feed. Poor selectivity - catalyst circulation issues, temperature maldistribution; check slide valves, distributor. Systematic approach: one variable at a time, validate with test runs, monitor response.

Biofuels integration options: Co-processing - blend bio-feedstocks (vegetable oil, animal fat, pyrolysis oil) with petroleum feeds in existing units. Hydrotreating co-processing: fatty acids converted to paraffins (renewable diesel). FCC co-processing: bio-oil adds oxygen, affects product distribution. Standalone renewable diesel - dedicated hydrotreater for lipid feedstocks, produces drop-in diesel. Higher hydrogen consumption than petroleum HDS. Bio-jet - hydroprocessed esters and fatty acids (HEFA) meeting jet fuel specifications. Ethanol integration - ETBE production for gasoline blending using existing alkylation/MTBE infrastructure. Challenges: feedstock variability and availability, higher hydrogen demand for deoxygenation, modified catalyst requirements, and supply chain logistics. Economics depend on feedstock cost, carbon credit value, and product premiums. Many refiners adding renewable diesel capacity using existing or modified infrastructure.