Refinery Process Air Emissions
Catalytic or thermal cracking units are a serious 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 serious source of two to four different air pollutants (particulates, nitrogen oxides, carbon monoxide and sulfur oxides) in an oil refinery, depending upon the kind of fuel burned in them. Catalytic reforming units are a significant 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 just one major air pollutant at an oil refinery. All 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 foremost source of inorganic chlorine (primarily hydrochloric acid) air emissions in an oil refinery is catalytic reforming units. The main oil refinery air emission source of reduced sulfur compounds is sulfur recovery plants.
Initially the crude oil entering a refinery is distilled at atmospheric pressure to provide six fractions; naphtha, gasoline, distillate, gas oil, lighter ends and reduced crude. The gas oil is further treated by catalytic cracking to interrupt 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 throughout 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 touch 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 key 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 so as to take care of 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 in addition 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 whole combustion regenerator is used and operated at 1-3% oxygen levels by adding excess air.
SOx scavenging additives also may be added to the regenerator so as to reduce SOx 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’s to be recycled. The particulate and gaseous emissions from the catalyst regenerator are the key air emission source from the catalytic cracking process.
Catalytic reforming employs a series of reactions conducted over a platinum or platinum/rhenium catalyst to alter or reform the structure of hydrocarbons. The purpose of those reactions in an oil refinery is to extend the octane value of the hydrocarbons by, for instance, dehydrogenating naphthenes to form aromatics.
The naphtha used as a reforming process feedstock is first treated to remove sulfur from it since that may 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’re a major source of refinery air emissions (Table 1). In addition, the reforming catalyst should be regenerated frequently, and this can be a big 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 primary reactor stage has decreased and reforming stops. The liquid naphtha/aromatic mixture then passes through a second heat exchanger to boost 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 should 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 method or by continuously regenerating a small fraction of the full amount of catalyst within 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 permit coke burn-off to occur under controlled conditions. Chlorine should be added to the catalyst right now to return it to the active form (metal chloride). Hydrogen must then be introduced to scale back 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) throughout the cracking and hydrotreating processes at an oil refinery. The acid gas is generally faraway 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, CS2 and H2S ) which are potentially toxic air pollutants. They are also extremely odorous compounds that can lead to 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 within the acid gas stream. The reaction is catalyzed by activated alumina and produces solid sulfur, water vapor and heat ( 2H2S + SO2 = 3S + 2H2O ). It is a reversible reaction so it is conducted in a series of reactors with cooling between reactors with a view to condense out the solid sulfur product. This drives the reaction towards completion so as to maximise hydrogen sulfide removal efficiency. Auxiliary burners then reheat the gas stream previous to the following reactor in order to maximize the reaction rate.
The recovered crude petroleum sulfur can be used within the refinery to produce sulfuric acid if there’s an onsite sulfuric acid plant. Many oil refineries use sulfuric acid in isomerization and alkylation processes to extend the value of their petroleum products. If not, the sulfur might 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 essentially the most cost-effective method of reducing refinery sulfur compound air emissions.
In order to meet stricter air pollution regulations, many oil refineries within 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 within 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 supply 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 within 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 that 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 within the refinery to enhance their economic value. It’s 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 on the market. Coking sharply reduces the amount 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 sort of 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 may 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 generally operated with liquid sprays onto a few of the distillation trays so as to forestall coke formation that plugs the trays. The coke is hydraulically transported into the method 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 can also be 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 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 set roof that is permanently attached to the tank sides and does not move. As the temperature changes attributable 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 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 together with the liquid temperature, hydrocarbon vapors are created in the top space above the liquid hydrocarbons. Then, when the liquid level rises together with the liquid temperature, hydrocarbon vapors escape the tank as fugitive air emissions that will must be controlled.
Wastewater streams in an oil refinery usually contain traces of hydrocarbons in addition to dissolved amine or sulfur compounds. Through 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 same old fugitive emission sources are open trenches, collection sumps and wastewater collection system vents. Open top wastewater treatment units similar to oil/water (API) separators, aeration basins, clarifiers, etc. can be the source of fugitive air emissions.
Cooling towers evaporate water with a purpose to remove the surplus 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 so as to perform 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 within the cooling tower in addition to a few of the cooling water. This results in fugitive hydrocarbon air emissions.
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 systems permit the removal of liquids and vapors from process units in an effort to permit shutdown of the process unit for maintenance/repair or to stop 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 every process unit. Because this transfer can allow the discharge of very concentrated air emissions, the blowdown system is usually connected to a refinery flare unit as a way to destroy these high concentration air emissions.
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 permits 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 take care of the vacuum within the distillation column. The hydrocarbon emissions are usually controlled by incineration in process furnaces or steam boilers.
Steam boilers are utilized in oil refineries to offer 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 so as 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. NOx 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 essentially the most with residual oil as a fuel. In some refinery boilers cogeneration of both steam and electric power is practiced.
Process furnaces are utilized in oil refineries so as 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 very 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 SOx) or from the combustion process itself (e.g. NOx 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 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. NOx 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 probably the most with residual oil as a fuel.
Compressors are used to generate the high internal pressure required in certain refinery processes (e.g. hydrotreating units) with a purpose to optimize process yield. These compressors are driven by either reciprocating internal combustion engines or by gas turbines. Fuel combustion in engines ends 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. NOx 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 similar to 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 refined products to construct up in the tank which must be vented to atmosphere along with the air displaced from the tank. The hydrocarbon emissions contained within 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 akin to gasoline from refinery storage tanks to a tank truck. Filling the tank truck allows vapors of the refined product to construct up crude petroleum in the tank which must be vented to atmosphere together with the air displaced from the tank. The hydrocarbon emissions contained within the vented air are usually conducted to an emission control device (refrigerated condenser, adsorber or incinerator) and either destroyed or recovered for reuse.