23-Chem-B6 Petroleum Refining and Petrochemicals · May 2016
Nivaar worked solution (AI-drafted; not reviewed by a licensed engineer)
Paper format: Open-book, 3 hours; five questions of equal value (10 marks each), and exactly five questions constitute a complete paper — all five printed questions are solved below. Most parts call for concise, qualitative essay answers built on the given flow sheets; Question III is a short characterization calculation.
Reference texts: Gary, Handwerk, Kaiser & Geddes, Petroleum Refining: Technology and Economics (5th ed., CRC Press) — refinery configuration, conversion and treating units, product cuts; Fahim, Al-Sahhaf & Elkilani, Fundamentals of Petroleum Refining (Elsevier) — crude characterization factors, hydrotreating, coking, catalytic cracking; Jones & Pujadó, Handbook of Petroleum Processing (Springer) — unit operating windows; supporting property data from Perry’s Chemical Engineers’ Handbook (9th ed.).
Question text not reproduced: the examination questions are © Engineers and Geoscientists BC. Open the official past paper (linked at the top of this page) to read the question, then follow the worked solution below.
(1) Source of the feed. The feed is a straight-run or cracked distillate cut drawn from upstream separation — for example naphtha, kerosene or gas oil from the crude/vacuum units (or a cracked stream). It is the sulphur- and nitrogen-bearing hydrocarbon stream that must be cleaned before it can be reformed, blended or catalytically cracked.
(2) Reaction temperature and pressure. Hydrotreating runs at roughly 300–400 °C and elevated hydrogen partial pressure, typically 30–70 bar (about 3–7 MPa) for distillate HDS (higher, 100 bar+, for heavy gas-oil and residue service). High H₂ pressure drives the desulphurization equilibrium and suppresses coking of the catalyst.
(3) Thermally, endothermic or exothermic? The hydrotreating reactions (hydrogenation of sulphur, nitrogen and olefins) are exothermic. The reactor temperature therefore rises across the bed, and hydrogen “quench” is often injected between beds to control the exotherm.
(4) Catalyst for sulphur removal. A cobalt–molybdenum (Co–Mo) catalyst on a γ-alumina support, used in its sulphided form, is the classic HDS catalyst; nickel–molybdenum (Ni–Mo/Al₂O₃) is used when more nitrogen removal or aromatic saturation is also required. Both are sulphided metal-sulphide catalysts.
(5) Three streams from the phase separator. The high-pressure (cold) separator splits the cooled reactor effluent into three phases: (i) a hydrogen-rich recycle gas (containing H₂S, sent to amine treating and then back to the reactor), (ii) a liquid hydrocarbon product (the desulphurized oil, sent to the stripper), and (iii) a sour-water phase (the injected wash water now carrying dissolved NH₃ and H₂S/salts).
(6) Why water is used. Wash water is injected into the reactor effluent to dissolve and wash out ammonium salts — chiefly ammonium bisulphide (NH₄HS) formed from the NH₃ and H₂S liberated in the reactor. Without water these salts deposit in the cooler tubes and cause plugging and under-deposit corrosion; the water keeps them in solution and carries them out as sour water.
(7) Two heat exchangers, one before and one after water injection. The exchanger before water injection is a feed/effluent exchanger that recovers heat — the hot reactor effluent preheats the incoming feed, and in doing so its own temperature is dropped toward the range where wash water can be added. The exchanger (cooler) after water injection then cools the combined effluent-plus-water stream down to separator temperature so the gas, oil and sour-water phases disengage cleanly. Splitting the duty this way recovers useful heat first, and only then applies the final trim cooling once the water has been added at a safe temperature (water is added below the point where it would flash or where salts would already have deposited).
