Refinery Process Air Emissions ppt

Refinery Process Air Emissions The most significant air emission sources in oil refineries are catalytic or thermal cracking units, catalytic reformer units, sulfur recovery plants, storage vessels, fluid coking units wastewater streams, cooling towers, equipment leaks, blowdown systems, vacuum distillation units, steam boilers, process furnaces, process heaters, compressor engines, barge or ship loading and gasoline loading racks specifically located at petroleum refineries. Table 1 identifies the air pollutants from these air emission sources and summarizes US EPA publication AP-42 estimates of the uncontrolled emissions from these oil refinery air emission sources. It should be noted that in many cases these refinery air emissions have already been controlled in order to meet specific US or overseas air emission regulations. Table 1: Significant Refinery Air Emission Sources, Air Pollutants And Emission Factors* Refinery Process Air Pollutant Emission Factor** Catalytic Cracking (Fluid Bed) Particulates 242 Carbon Monoxide 13,700 Sulfur Dioxide 493 Nitrogen Oxides 71 Hydrocarbons 220 Aldehydes 19 Ammonia 54 Catalytic Cracking (Moving Bed) Particulates 17 Carbon Monoxide 3,800 Sulfur Dioxide 60 Nitrogen Oxides 5 Hydrocarbons 87 Aldehydes 12 Ammonia 6 Catalytic Reforming Hydrocarbons 25 Inorganic Chlorine 4,450 Sulfur Recovery Plant Sulfur Dioxide 359 lbs/ton sulfur recovered Reduced Sulfur (H 2 S, CS 2, COS) 0.65 lbs/ton sulfur recovered 10/25/12 Ref inery Process Air Emissions www.mcilv ainecompany .com/brochures/ref inery _process.htm Storage Vessels Hydrocarbons No single emission factor Fluid Coking Particulates 523 Wastewater Streams Hydrocarbons 0.097 Cooling Towers Hydrocarbons 0.0048 Equipment Leaks Hydrocarbons 0.034 Blowdown System Hydrocarbons 580 Vacuum Distillation Hydrocarbons 50 Steam Boiler, Process Furnace or Process Heater (Below 100 Million Btu/hr capacity) Particulates 10 lbs/1,000 gallon #6 fuel oil Nitrogen Oxides 55 lbs/1,000 gallon #6 fuel oil Carbon Monoxide 5 lbs/1,000 gallon #6 fuel oil Sulfur Oxides 157 x sulfur percentage in fuel/1,000 gallon #6 fuel oil Steam Boiler, Process Furnace or Process Heater (Below 100 Million Btu/hr capacity) Particulates 2 lbs/1,000 gallon distillate oil Nitrogen Oxides 20 lbs/1,000 gallon distillate oil Carbon Monoxide 5 lbs/1,000 gallon distillate oil Sulfur Oxides 142 x sulfur percentage in fuel/1,000 gallon distillate oil Steam Boiler, Process Furnace or Process Heater (Above 100 Million Btu/hr capacity) Particulates 2 lbs/1,000 gallon #2 fuel oil Nitrogen Oxides 24 lbs/1,000 gallon #2 fuel oil Carbon Monoxide 5 lbs/1,000 gallon #2 fuel oil Sulfur Oxides 157 x sulfur percentage in fuel/1,000 gallon #2 fuel oil Compressor Engine (Reciprocating) Hydrocarbons 1.4 lbs/1000 cubic feet gas fuel Carbon Monoxide 0.43 lbs/1000 cubic feet gas fuel Nitrogen Oxides 3.4 lbs/1000 cubic feet gas fuel Sulfur Oxides 2 x sulfur percentage in fuel/1000 cubic feet gas fuel Compressor Engine (Gas Turbine) Hydrocarbons 0.02 lbs/1000 cubic feet gas fuel Carbon Monoxide 0.12 lbs/1000 cubic feet gas fuel 10/25/12 Ref inery Process Air Emissions 3/10www.mcilv ainecompany .com/brochures/ref inery _process.htm Nitrogen Oxides 0.3 lbs/1000 cubic feet gas fuel Sulfur Oxides 2 x sulfur percentage in fuel gas/1000 cubic feet gas fuel Vessel Loading (Barge) Hydrocarbons 3.4 lbs/1,000 gallons transferred Vessel Loading (Ship) Hydrocarbons 1.8 lbs/1,000 gallons transferred Gasoline Rack Loading Hydrocarbons 995 lbs/1,000 gallons transferred * Uncontrolled air emissions from US EPA Document AP-42 ** Expressed as lbs/1,000 bbl fresh feed unless otherwise specified Catalytic or thermal cracking units are a major source of seven different air pollutants (particulates, carbon monoxide, sulfur dioxide, nitrogen oxides, hydrocarbons, aldehydes and ammonia) in an oil refinery. Steam boilers are a major source of two to four different air pollutants (particulates, nitrogen oxides, carbon monoxide and sulfur oxides) in an oil refinery, depending upon the type of fuel burned in them. Catalytic reforming units are a major source of two different air pollutants (hydrocarbons and inorganic chlorine) in an oil refinery. Sulfur recovery plants are also a major source of two air pollutants (sulfur dioxide and reduced sulfur compounds) in a refinery. All other processing operations (storage vessels, fluid coking, wastewater streams, cooling towers, equipment leaks, blowdown systems, vacuum distillation, barge or ship loading and gasoline rack loading) are the source of only one major air pollutant at an oil refinery. All of the above mentioned are hydrocarbon emission sources with the exception of fluid coking, which is a particulate emission source. Major sources of particulate air emissions in an oil refinery are catalytic or thermal cracking units, fluid coking units, steam boilers, process furnaces, and process heaters (if the latter three are burning liquid fuel). Major oil refinery carbon monoxide emission sources are catalytic crackers, steam boilers, process furnaces and process heaters. Major sulfur dioxide air emission sources in an oil refinery are catalytic or thermal cracking units, sulfur recovery plants, steam boilers, process furnaces, process heaters and compressor engines (if the latter four are burning high sulfur gaseous or liquid fuel). Major oil refinery nitrogen oxides emission sources are catalytic or thermal cracking units, steam boilers, process furnaces, process heaters and compressor engines. Major sources of hydrocarbon air emissions in an oil refinery are catalytic or thermal cracking units, catalytic reforming units, storage vessels, wastewater streams, cooling towers, equipment leaks, blowdown systems, vacuum distillation units, compressor engines, barge or ship loading and gasoline rack loading. Major oil refinery aldehydes and ammonia air emission sources are catalytic or thermal crackers. The major source of inorganic chlorine (primarily hydrochloric acid) air emissions in an oil refinery is catalytic reforming units. The major oil refinery air emission source of reduced sulfur compounds is sulfur recovery plants. Catalytic Cracking Initially the crude oil entering a refinery is distilled at atmospheric pressure to produce six fractions; naphtha, gasoline, distillate, gas oil, lighter ends and reduced crude. The gas oil is further treated by catalytic cracking to break down its long chain hydrocarbons into lower boiling point components. The resulting lower boiling point components can then be used by the refinery for gasoline and distillate fuel production. Catalytic cracking units in an oil refinery use a alumina, silica or zeolite based catalyst in a moving or fluidized bed at elevated temperature to break down the long chain hydrocarbons in the gas phase. Fluid bed catalytic cracking has superseded moving bed catalytic cracking worldwide but there are still existing oil refineries with the obsolete moving bed catalytic cracking systems. Both process variations have significant particulate and gaseous air emissions which were identified in Table 1. The air emissions occur during the regeneration of the catalyst. Figure 1 is the flow diagram of a typical fluid catalytic cracking unit at an oil refinery. Preheated liquid gas oil is fed into the bottom of the catalytic cracker where it comes in contact with the newly regenerated hot alumina, silica or zeolite catalyst. This contact vaporizes the gas oil and begins the cracking reaction on the hot catalyst surface. The catalyst is in the powdered form and is carried upward, along with the gas oil vapors, from the riser section into the reactor vessel where all of the catalytic cracking reactions are completed. The major reaction products are the shorter chain hydrocarbons, but some carbon monoxide and carbon are also formed. The carbon, referred to as coke, deactivates the cracking catalyst and must be removed on a frequent basis in order to maintain an optimum catalytic cracking process. Figure 1: Schematic of FCC Unit The hydrocarbon products exiting the fluid catalytic cracking process reactor are separated from the catalyst particles by flow impingers followed by cyclonic separators. The hydrocarbon products are subsequently sent to a fractionation column for product separation while the separated catalyst is sent to a regenerator. The catalyst is first steam stripped to remove any hydrocarbons from it prior to regeneration by coke burnoff. The coke burn-off is accomplished in the regeneration vessel by addition of air to react with the coke and also to fluidize the catalyst. This burn-off is exothermic and and occurs at 1,000 ° F to 1,200 ° F in a partial catalyst regenerator operated at low levels (500 ppmv or less) of oxygen from added air. The burn-off occurs at 1,200 ° F to 1,400 ° F in cases where a complete combustion regenerator is used and operated at 1-3% oxygen levels by adding excess air. SO x scavenging additives also may be added to the regenerator in order to reduce SO x emissions, and fresh catalyst may also be added to make up for losses from the system. Gases exiting the catalyst regenerator are separated by cyclones from the solid catalyst that is to be recycled. The particulate and gaseous emissions from the catalyst regenerator are the major air emission source from the catalytic cracking process. Catalytic Reforming Catalytic reforming employs a series of reactions conducted over a platinum or platinum/rhenium catalyst to change or reform the structure of hydrocarbons. The purpose of these reactions in an oil refinery is to increase the octane value of the hydrocarbons by, for example, dehydrogenating naphthenes to form aromatics. The naphtha used as a reforming process feedstock is first treated to remove sulfur from it since that would poison the platinum in the reforming catalyst. The reaction is endothermic and heat must be applied to the process in between the multiple reactors used in series for the reforming process. Two other types of catalytic reforming use either cyclic regeneration or continuous regeneration of the catalyst. Heat exchangers and fired heaters are used to add the required heat to the reforming process, and they are a significant source of refinery air emissions (Table 1). In addition, the reforming catalyst must be regenerated on a regular basis, and this is also a significant air emission source in a refinery. In a catalytic reformer, the liquid naphthas are first either desulfurized by reaction with zinc oxide to form zinc sulfide or hydrodesulfurized over a cobalt-molybdenum catalyst to form hydrogen sulfide. The resulting sulfur dioxide (from regenerating zinc sulfide) or hydrogen sulfide is then sent to the sulfur recovery plant of the refinery. The liquid naphtha feedstock is next raised to reaction temperature by passing it through a heat exchanger into the first stage reforming reactor. Once the reforming reaction is partially completed, the temperature of the liquid in the first reactor stage has decreased and reforming stops. The liquid naphtha/aromatic mixture then passes through a second heat exchanger to raise it back to reaction temperature before entering the second stage reforming reactor. This sequence of heat exchange and then reaction is repeated in subsequent stages until the desired naphtha conversion to aromatics is achieved. The reforming catalyst must be regenerated on a regular basis because it is deactivated by carbon buildup (coke) or catalyst poisons present in the naphtha feedstock. The catalyst must be regenerated by shutting down the reforming process, by removing individual reactors from the process or by continuously regenerating a small fraction of the total amount of catalyst in the reactors. Each has advantages and disadvantages, and therefore all three methods of catalyst regeneration are practiced worldwide. Semi-regenerative reforming technology interrupts the reforming process when the catalyst must be regenerated. The reactors are then depressurized and any hydrocarbon vapors purged with nitrogen to a carbon adsorber, thermal oxidizer or refinery flare. Air is then introduced and recirculated through the compressor to allow coke burn-off to occur under controlled conditions. Chlorine must be added to the catalyst at this time to return it to the active form (metal chloride). Hydrogen must then be introduced to reduce the regenerated metal catalyst from the oxide form. The latter two catalyst regenerating steps produce significant hydrochloric acid emissions. Sulfur Recovery Plant Sulfur in the crude oil feedstock is converted to predominately hydrogen sulfide (also called acid gas) during the cracking and hydrotreating processes at an oil refinery. The acid gas is normally removed from the cracking and hydrotreating process exhausts by an amine solvent absorption process. The amine solution is regenerated by heating and the concentrated acid gas is then sent to a sulfur recovery plant located within the refinery. The exhaust of the sulfur recovery plant, as reported in Table 1, contains reduced sulfur compounds ( COS, CS 2 and H 2 S ) that are potentially toxic air pollutants. They are also extremely odorous compounds that can result in 10/25/12 Ref inery Process Air Emissions 6/10www.mcilv ainecompany .com/brochures/ref inery _process.htm community odor complaints. A typical sulfur recovery plant uses the Claus process, or a variation thereof. Approximately one third of the acid gas is combusted with air to form sulfur dioxide, which in turn is reacted with the hydrogen sulfide in the acid gas stream. The reaction is catalyzed by activated alumina and produces solid sulfur, water vapor and heat ( 2H 2 S + SO 2 = 3S + 2H 2 O ). This is a reversible reaction so it is conducted in a series of reactors with cooling between reactors in order to condense out the solid sulfur product. This drives the reaction towards completion in order to maximize hydrogen sulfide removal efficiency. Auxiliary burners then reheat the gas stream prior to the next reactor in order to maximize the reaction rate. The recovered sulfur can be used within the refinery to produce sulfuric acid if there is an onsite sulfuric acid plant. Many oil refineries use sulfuric acid in isomerization and alkylation processes to increase the value of their petroleum products. If not, the sulfur can be sold for use in producing sulfuric acid offsite or for use in other processes requiring elemental sulfur. There is currently little or no profit in producing sulfur from a Claus plant, but this sulfur removal process is usually the most cost-effective method of reducing refinery sulfur compound air emissions. In order to meet stricter air pollution regulations, many oil refineries in the United States, Japan and Europe have installed sulfur removal processes on the tail gas from the Claus process. The commonly employed methods of tail gas treatment include catalytic reduction, amine absorption and incineration. Catalytic reduction produces hydrogen sulfide from the mixed sulfur compounds in the Claus plant tail gas that can be absorbed in amine solvent and recycled back to the inlet of the sulfur recovery plant. Amine absorption increases the hydrogen sulfide removal efficiency of the Claus plant by reducing the hydrogen sulfide content of the tail gas. Thermal oxidation or incineration converts all sulfur compounds in the Claus plant tail gas to sulfur dioxide which can be scrubbed and neutralized to produce sodium sulfite or sodium bisulfite. The emissions from the sulfur recovery plant occur in the exhaust from the Claus plant, if no tail gas treatment is used, or the exhaust from the tail gas treatment unit. The exhaust gas from the Claus process usually contains less than 1% mixed sulfur compounds, indicating a sulfur removal efficiency of over 98%. A tail gas treatment process can reduce the mixed sulfur compounds in the Claus plant exhaust to less than 100 ppmv, increasing the overall sulfur removal efficiency from the tail gas to over 99.9%. Delayed or Fluid Coking Delayed or fluid coking is a thermal cracking process that upgrades the value of refinery vacuum distillation residues and aromatic oils. The vacuum distillation residues contain asphaltic compounds which are primarily heterocyclic hydrocarbons. The aromatic oils, usually decant oil or pyrolysis residues, are primarily polynuclear aromatics with six carbon aromatic rings fused together. The decant oil is a residue of the catalytic cracking process whereas the pyrolysis residues are from the thermal cracking process. Coking operations can be used to upgrade any low volatility residual solids in the refinery to improve their economic value. It is literally a petroleum refinery “garbage can” to dispose of undesirable residuals by turning them into valuable products. Coking also removes metals and other contaminants from the coker feed and concentrates them in the solid coke. The liquid and gaseous products of delayed or fluid coking are therefore more suitable for internal refinery use than for sale. Coking sharply reduces the volume and disposal cost of solid wastes from an oil refinery by converting them into useful byproducts. The value of fluid or delayed coking to a modern refinery is almost 10/25/12 Ref inery Process Air Emissions 7/10www.mcilv ainecompany .com/brochures/ref inery _process.htm incalculable in these times of strict environmental regulations. Delayed coking is the predominant coking method in petroleum refineries but some have adopted a newer coking method called fluid coking. Approximately 75 percent of refineries with coking operations use delayed coking whereas approximately 25 percent use a fluid coking process. Delayed coking has no significant air emissions but fluid coking produces air emissions consisting of coke fines. Figure 2 is a flow diagram of a refinery delayed coking unit. Fluid coking is a continuous process where a fluid bed reactor is heated to convert the non-volatile coker feed (e.g. vacuum distillation residue) into solid coke and a mixture of non-condensable gaseous volatile liquid products that can be fractionated in subsequent process steps. The cold coke exits the fluid bed reactor at the bottom while the volatile liquid and gaseous products exit the reactor at the top. The latter are separated in the coke fractionator, which is a distillation column dedicated to the delayed coking process. The coke fractionator is normally operated with liquid sprays onto some of the distillation trays in order to prevent coke formation that plugs the trays. The coke is hydraulically transported into the process heater where it is reheated and either returned to the fluid bed reactor or sent to a coke recovery and storage area. This latter step is where coke fines can become airborne air pollutants. Figure 2: Schematic of Delayed Coking Unit Because the feedstock of a delayed or fluid coker has a high sulfur content, gaseous sulfur compounds are produced. Gaseous hydrocarbons and organic HAPs (e.g. benzene) are also produced in the delayed coking process. They are recovered in the coker fractionator whereas the gaseous sulfur compounds are usually sent on to the sulfur recovery plant and removed there. Carbon monoxide is also produced which is usually incinerated for its fuel value in a CO boiler. The only direct releases to atmosphere from the coking process is therefore particulates Storage Vessels Storage tanks and spheres are typical vessels used at oil refineries to contain crude oil, processed intermediates or refined products. Cylindrical tanks are generally used for storage of volatile liquids (e.g. gasoline) whereas spheres are generally used for storage of condensable (e.g. propane under pressure) or non-condensable gases (e.g. methane). Tanks may have either a floating roof with a sliding seal attachment to the tank sides, where the roof rises and falls with the liquid level, or a fixed roof that is permanently attached to the tank sides and does not move. As the temperature changes due to ambient condition changes, the floating roof tank adjusts the liquid volume automatically and vapor losses are minimal. Adding a second sliding seal will virtually eliminate vapor volume automatically and vapor losses are minimal. Adding a second sliding seal will virtually eliminate vapor losses. A fixed roof tank has no such flexibility and a vapor head space exists above the liquid level of the tank. When the liquid level falls along with the liquid temperature, hydrocarbon vapors are created in the head space above the liquid hydrocarbons. Then, when the liquid level rises along with the liquid temperature, hydrocarbon vapors escape the tank as fugitive air emissions that may need to be controlled. Wastewater Streams Wastewater streams in an oil refinery usually contain traces of hydrocarbons as well as dissolved amine or sulfur compounds. During the transfer of the wastewater from the process to the central treatment facility, hydrocarbon, amine and sulfur compound vapors can escape into the atmosphere as fugitive emissions. The usual fugitive emission sources are open trenches, collection sumps and wastewater collection system vents. Open top wastewater treatment units such as oil/water (API) separators, aeration basins, clarifiers, etc. can also be the source of fugitive air emissions. Cooling Towers Cooling towers evaporate water in order to remove the excess heat from processing units at an oil refinery. Cooling water is cycled continuously between the cooling tower and the processing units where the heat is generated in order to accomplish this. Although in theory the cooling water is never in direct contact with the liquid hydrocarbons being processed, in reality leaks and cross contamination sometimes does occur. Therefore volatile hydrocarbons may be evaporated in the cooling tower as well as some of the cooling water. This results in fugitive hydrocarbon air emissions. Equipment Leaks Equipment leaks normally encountered in an oil refinery include pipe flanges, threaded pipe connections, pump seals, compressor seals and valve packing. There are literally thousands of such potential leak sources in a typical oil refinery. Reasons for leaks can include normal wear and tear, poor quality or design of components, poor maintenance or improper choice of materials. Volatile hydrocarbons can then be leaked from the processing units into the ambient environment from any of the above mentioned sources. Leak detection and repair programs can reduce but not eliminate these fugitive emissions. Blowdown System Blowdown systems permit the removal of liquids and vapors from process units in order to permit shutdown of the process unit for maintenance/repair or to prevent dangerous high temperature or high pressure conditions from occuring in it. A refinery blowdown system consists of valves, piping, surge vessels, etc. to allow safe transfer of process liquids or vapors out of each process unit. Because this transfer can allow the release of very concentrated air emissions, the blowdown system is usually connected to a refinery flare unit in order to destroy these high concentration air emissions. Vacuum Distillation Vacuum distillation, which follows the atmospheric distillation of crude oil, allows the separation of very high boiling point petroleum fractions without decomposing and polymerizing them. Topped crude from the atmospheric distillation unit is first heated to about 400 ° C by a process heater, then it is flashed into a vacuum distillation column maintained at absolute pressures below 1500 kilograms per square meter. This allows separation of the topped crude into common boiling point fractions by vaporization and condensation. Air emissions are from condensers following the steam ejectors and vacuum pumps used to maintain the vacuum in 10/25/12 9/10www.mcilv ainecompany .com/brochures/ref inery _process.htm emissions are from condensers following the steam ejectors and vacuum pumps used to maintain the vacuum in the distillation column. The hydrocarbon emissions are usually controlled by incineration in process furnaces or steam boilers. Steam Boilers Steam boilers are used in oil refineries to provide indirect heat for process units and also vacuum for steam ejectors used, for example, in vacuum distillation units. Fuel is combusted in an insulated chamber and transferred to water in tubes in order to generate the steam. The flue gas from the combustion chamber then exits the boiler through an exhaust stack. Air emissions occur both from the combustion of fuel impurities (e.g. particulates and sulfur) and from the combustion process itself (e.g. NO x and CO). Steam boilers use natural gas, refinery fuel gas, fuel oil or residual oil as fuel. The potential air emissions are the least with natural gas fuel and are the most with residual oil as a fuel. In some refinery boilers cogeneration of both steam and electric power is practiced. Process Furnaces Process furnaces are used in oil refineries in order to heat viscous process fluids or solids to a very high processing or transfer temperature. Fuel is combusted in an insulated chamber and the heat transferred to either tubes or a cylindrical vessel containing the viscous fluid or solid. In some case the hot flue gas of the furnace is directly in contact with the viscous fluid or solid. A good example is the above mentioned fluid coking process. Air emissions occur from the combustion of fuel impurities (e.g. metals and sulfur resulting in particulates and SO x ) or from the combustion process itself (e.g. NO x and CO). Process furnaces use natural gas, refinery fuel gas, fuel oil or residual oil as fuel. The potential air emissions are greatest with residual oil as a fuel. Process Heaters Process heaters are used in oil refineries to indirectly heat process fluids to a moderate processing temperature. A good example is the above mentioned catalytic reforming process. Fuel is combusted in an insulated chamber and the heat transferred to either tubes or a cylindrical vessel containing the process fluid. Air emissions occur from the combustion of fuel impurities (e.g. particulates and sulfur) or from the combustion process itself (e.g. NO x and CO). Process heaters use natural gas, refinery fuel gas, fuel oil or residual oil as fuel. The potential air emissions are the least with natural gas fuel and are the most with residual oil as a fuel. Compressor Engines Compressors are used to generate the high internal pressure required in certain refinery processes (e.g. hydrotreating units) in order to optimize process yield. These compressors are driven by either reciprocating internal combustion engines or by gas turbines. Fuel combustion in engines results in an exhaust gas containing air emissions. Air emissions occur from either the combustion of fuel impurities (e.g. particulates and sulfur) or from the combustion process itself (e.g. NO x and CO). Reciprocating compressor engines use natural gas, refinery fuel gas or diesel oil as a fuel. Their potential air emissions are the least with natural gas fuel and are the most with diesel oil as a fuel. More recently, gas turbines have been employed to drive very large oil refinery compressors. They use natural gas, refinery fuel gas or distillate oil as a fuel. Their potential air emissions are the least with natural gas fuel and are the most distillate oil as a fuel. Barge or Ship Loading Barge or ship loading requires the transfer of crude oil or refined products such as gasoline from on shore storage tanks to the barge or ship tank. The barge or ship tanks, while filling, allow vapors of the crude oil or 10/25/12 Ref inery Process Air Emissions 10/10www.mcilv ainecompany .com/brochures/ref inery _process.htm storage tanks to the barge or ship tank. The barge or ship tanks, while filling, allow vapors of the crude oil or refined products to build up in the tank which must be vented to atmosphere along with the air displaced from the tank. The hydrocarbon emissions contained in the vented air are usually conducted to an emission control device (refrigerated condenser, absorber, adsorber or incinerator) and either destroyed or recovered for reuse Gasoline Rack Loading Gasoline rack loading requires the transfer of refined products such as gasoline from refinery storage tanks to a tank truck. Filling the tank truck allows vapors of the refined product to build up in the tank which must be vented to atmosphere along with the air displaced from the tank. The hydrocarbon emissions contained in the vented air are usually conducted to an emission control device (refrigerated condenser, adsorber or incinerator) and either destroyed or recovered for reuse. . overseas air emission regulations. Table 1: Significant Refinery Air Emission Sources, Air Pollutants And Emission Factors* Refinery Process Air Pollutant. Refinery Process Air Emissions The most significant air emission sources in oil refineries are catalytic