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2015 Ner Production Guidelines in Oil Refinery Sector

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2015 Ner Production Guidelines in Oil Refinery Sector 2015 Cleaner Production Guidelines in Oil Refinery Sector Gujarat Cleaner Production Centre (Established by Industries & Mines Department, GoG) ENVIS Centre on: Cleaner Production/Technology Supported by: Ministry of Environment, Forest & Climate Change, Government of India Block No: 11-12, 3rd Floor, UdhyogBhavan, Gandhinagar Phone: + 91 (079) 232 44 147 Mail: [email protected] ; [email protected]; Website: www.gcpcgujarat.org.in, www.gcpcenvis.nic.in Oil Refinery An oil refinery or petroleum refinery is an industrial process plant where crude oil is processed and refined into more useful products such as petroleum naphtha, gasoline, diesel fuel, asphalt base, heating oil, kerosene and liquefied petroleum gas. Oil refineries are typically large, sprawling industrial complexes with extensive piping running throughout, carrying streams of fluids between large chemical processing units. Common process units found in a refinery 1. Desalter unit washes out salt from the crude oil before it enters the atmospheric distillation unit. 2. Atmospheric distillation unit distills crude oil into fractions. 3. Vacuum distillation unit further distills residual bottoms after atmospheric distillation. 4. Naphtha hydro treater unit uses hydrogen to desulfurize naphtha from atmospheric distillation. Must hydrotreat the naphtha before sending to a Catalytic Reformer unit. 5. Catalytic reformer unit is used to convert the naphtha-boiling range molecules into higher octane reformate (reformer product). The reformate has higher content of aromatics and cyclic hydrocarbons). An important byproduct of a reformer is hydrogen released during the catalyst reaction. The hydrogen is used either in the hydrotreater or the hydrocracker. 6. Distillate hydrotreater unit desulfurizes distillates (such as diesel) after atmospheric distillation. 7. Fluid catalytic cracker (FCC) unit upgrades heavier fractions into lighter, more valuable products. 8. Hydrocracker unit uses hydrogen to upgrade heavier fractions into lighter, more valuable products. 9. Visbreaking unit upgrades heavy residual oils by thermally cracking them into lighter, more valuable reduced viscosity products. 10. Merox unit treats LPG, kerosene or jet fuel by oxidizing mercaptans to organic disulfides. 11. Alternative processes for removing mercaptans are known, e.g. doctor sweetening process and caustic washing. 12. Coking units (delayed coking, fluid coker, and flexicoker) process very heavy residual oils into gasoline and diesel fuel, leaving petroleum coke as a residual product. 13. Alkylation unit produces high-octane component for gasoline blending. 14. Dimerization unit converts olefins into higher-octane gasoline blending components. For example, butenes can be dimerized into isooctene which may subsequently be hydrogenated to formisooctane. There are also other uses for dimerization. 15. Isomerization unit converts linear molecules to higher-octane branched molecules for blending into gasoline or feed to alkylation units. 16. Steam reforming unit produces hydrogen for the hydrotreater or hydrocracker. 17. Liquefied gas storage vessels store propane and similar gaseous fuels at pressure sufficient to maintain them in liquid form. These are usually spherical vessels or "bullets" (i.e., horizontal vessels with rounded ends). 18. Storage tanks store crude oil and finished products, usually cylindrical, with some sort of vapor emission control and surrounded by an earthen berm to contain spills. 19. Amine gas treater, Claus unit, and tail gas treatment convert hydrogen sulfide from hydro desulfurization into elemental sulfur. 20. Utility units such as cooling towers circulate cooling water, boiler plants generates steam, and instrument air systems include pneumatically operated control valves and an electrical substation. 21. Wastewater collection and treating systems consist of API separators, dissolved air flotation (DAF) units and further treatment units such as an activated sludge biotreater to make water suitable for reuse or for disposal. 22. Solvent refining units use solvent such as cresol or furfural to remove unwanted, mainly aromatics from lubricating oil stock or diesel stock. 23. Solvent dewaxing units remove the heavy waxy constituent’s petrolatum from vacuum distillation products. Environmental Issues Potential environmental issues associated with petroleum refining include the following Air emissions Wastewater Wastes Air Emissions Exhaust Gases Exhaust gas and flue gas emissions (carbon dioxide (CO2), nitrogen oxides (NOX) and carbon monoxide (CO)) in the petroleum refining sector result from the combustion of gas and fuel oil or diesel in turbines, boilers, compressors and other engines for power and heat generation. Flue gas is also generated in waste heat boilers associated with some process units during continuous catalyst regeneration or fluid petroleum coke combustion. Flue gas is emitted from the stack to the atmosphere in the Bitumen Blowing Unit, from the catalyst regenerator in the Fluid Catalytic Cracking Unit (FCCU) and the Residue Catalytic Cracking Unit (RCCU), and in the sulfur plant, possibly containing small amounts of sulfur oxides. Low-NOX burners should be used to reduce nitrogen oxide emissions. Venting and Flaring Venting and flaring are important operational and safety measures used in petroleum refining facilities to ensure that vapors gases are safely disposed of. Petroleum hydrocarbons are emitted from emergency process vents and safety valves discharges. These are collected into the blow- down network to be flared. Excess gas should not be vented, but instead sent to an efficient flare gas system for disposal. Emergency venting may be acceptable under specific conditions where flaring of the gas stream is not possible, on the basis of an accurate risk analysis and integrity of the system needs to be protected. Justification for not using a gas flaring system should be fully documented before an emergency gas venting facility is considered. Before flaring is adopted, feasible alternatives for the use of the gas should be evaluated and integrated into production design to the maximum extent possible. Flaring volumes for new facilities should be estimated during the initial commissioning period so that fixed volume flaring targets can be developed. The volumes of gas flared for all flaring events should be recorded and reported. Continuous improvement of flaring through implementation of best practices and new technologies should be demonstrated. Following pollution prevention &control measures should be considered for gas flaring Implementation of source gas reduction measures to the maximum extent possible; Use of efficient flare tips, and optimization of the size and number of burning nozzles; Maximizing flare combustion efficiency by controlling and optimizing flare fuel / air / steam flow rates to ensure the correct ratio of assist stream to flare stream; Minimizing flaring from purges and pilots, without compromising safety, through measures including installation of purge gas reduction devices, flare gas recovery units, inert purge gas, soft seat valve technology where appropriate, and installation of conservation pilots; Minimizing risk of pilot blow-out by ensuring sufficient exit velocity and providing wind guards; Use of a reliable pilot ignition system; Installation of high integrity instrument pressure protection systems, where appropriate, to reduce over pressure events and avoid or reduce flaring situations; Installation of knock-out drums to prevent condensate emissions, where appropriate; Minimizing liquid carry-over and entrainment in the gas flare stream with a suitable liquid separation system; Minimizing flame lift off and / or flame lick; Operating flare to control odor and visible smoke emissions (no visible black smoke); Locating flare at a safe distance from local communities and the workforce including workforce accommodation units; Implementation of burner maintenance and replacement programs to ensure continuous maximum flare efficiency; Metering flare gas. To minimize flaring events as a result of equipment breakdowns and plant upsets, plant reliability should be high (>95 percent), and provision should be made for equipment sparing and plant turn down protocols. Fugitive Emissions Fugitive emissions in petroleum refining facilities are associated with vents, leaking tubing, valves, connections, flanges, packings, open-ended lines, floating roof storage tanks and pump seals, gas conveyance systems, compressor seals, pressure relief valves, tanks or open pits / containments, and loading and unloading operations of hydrocarbons. Depending on the refinery process scheme, fugitive emissions may include: Hydrogen. Methane. Volatile organic compounds (VOCs), (e.g. ethane, ethylene, propane, propylene, butanes, butylenes, pentanes, pentenes, C6-C9 alkylate, benzene, toluene, xylenes, phenol, and C9 aromatics). Polycyclic aromatic hydrocarbons (PAHs) and other semi volatile organic compounds. Inorganic gases, including hydrofluoric acid from hydrogen fluoride alkylation, hydrogen sulfide, ammonia, carbon dioxide, carbon monoxide, sulfur dioxide and sulfur trioxide from sulfuric acid regeneration in the sulfuric acid alkylation process, NOX, methyl tert-butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), t-amylmethyl ether (TAME), methanol, and ethanol. The main sources of concern include VOC emissions from cone roof storage tanks during loading and due to out-breathing; fugitive emissions
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