Method and apparatus for removing oxygenates from liquefied petroleum gas

Abstract

A method and apparatus for removing oxygenates from a C3 and / or C4 hydrocarbon petroleum stream includes washing the petroleum stream to absorb oxygenates to provide an oxygenate-depleted hydrocarbon stream and an oxygenate-rich water stream. The water stream is stripped to remove oxygenates into an oxygenate-enriched stream and an oxygenate-depleted water stream. The lean water stream may be recycled to the water scrubber.

Description

Technical Field

[0001] This field relates to the purification of liquefied petroleum gas (LPG). In particular, this field can relate to the purification of light gas streams from fluid catalytic cracking (FCC) units. Background Technology

[0002] Catalytic cracking can produce a variety of products from larger hydrocarbons. Typically, heavy hydrocarbon feedstocks, such as vacuum gas oil, are fed into catalytic cracking reactors (such as fluid catalytic cracking (FCC) reactors). This produces a variety of products, including gasoline products and / or light products, such as propylene and / or ethylene. With biorenewable feedstocks becoming more readily available, refineries are looking to feed heavy biorenewable feedstocks into FCC units to crack them into motor fuels.

[0003] When biorenewable bio-oils (such as pyrolysis oils or vegetable oils) are co-processed with fossil feedstocks, the oxygenated compound content of LPG from the FCC unit increases significantly. Oxygenated compounds in LPG are known to cause problems in downstream processes (such as catalytic polycondensation, alkylation, and mercaptan extraction oxidation units), therefore, oxygenated compounds must be removed to low levels to ensure smooth refinery operation and product specifications.

[0004] Oxygenated compound removal is one of the major challenges in co-processing bio-oils in FCC units, which is often economically advantageous due to government subsidies or avoidance of penalties. Summary of the Invention

[0005] A method and apparatus for removing oxygenated compounds from a petroleum feed stream of C3 and / or C4 hydrocarbons includes washing the petroleum feed stream with water to absorb the oxygenated compounds, thereby providing an oxygen-lean hydrocarbon feed stream and an oxygen-rich water feed stream. The water feed stream is stripped to remove the oxygenated compounds, resulting in an oxygen-rich feed stream and an oxygen-lean water feed stream. The lean water feed stream can be recycled to a water washing tower. Attached Figure Description

[0006] Figure 1 This is a schematic diagram of the method and apparatus disclosed herein.

[0007] Figure 2 This is a schematic diagram of the additional methods and apparatus disclosed herein.

[0008] definition

[0009] The term "connectivity" refers to the operative permission for fluid flow between enumerated components, which can be characterized as "fluid connectivity".

[0010] The term "downstream connectivity" means that in downstream connectivity at least a portion of the fluid flowing toward the body can be operatively flowed from the object with which it is fluidly connected.

[0011] The term "upstream connectivity" means that at least a portion of the fluid flowing out of the host in upstream connectivity can be operatively directed to an object in fluid communication with it.

[0012] The term "direct connection" means that fluid flow from an upstream component enters a downstream component without passing through any other intermediary container.

[0013] The term "indirect connection" refers to fluid flow from an upstream component entering a downstream component after passing through an intermediary container.

[0014] The term "bypass" means that an object is disconnected from the downstream entity at least within the scope of the bypass.

[0015] As used herein, the terms “major” or “dominant” mean greater than 50%, appropriately greater than 75%, and preferably greater than 90%.

[0016] The term "tower" refers to one or more distillation columns used to separate one or more components with different volatility. Unless otherwise specified, each column includes a condenser at the top of the column for condensing a portion of the overhead feed and returning a portion of the overhead feed to the top of the column, and a reboiler at the bottom of the column for evaporating a portion of the bottom feed and returning a portion of the bottom feed to the bottom of the column. The feed to the column may be preheated. The top pressure is the pressure of the vapor at the top of the column at the vapor outlet. The bottom temperature is the temperature at the bottom outlet of the liquid. Top and bottom lines refer to the net lines from any downstream reflux or reboiler to the column. Stripper columns may omit the reboiler at the bottom of the column, instead providing the heating requirements and separation power for a liquefied inert medium such as steam. Stripper columns typically feed from the top tray and remove the main product from the bottom.

[0017] As used herein, the term “rich component stream” refers to a rich component stream exiting a container that has a higher component concentration than the feed into the container.

[0018] As used herein, the term "lean component stream" refers to a lean stream exiting a container with a lower component concentration than the feed into the container.

[0019] As used herein, the term "separator" refers to a vessel having an inlet and at least one top vapor outlet and a bottom liquid outlet, and may also have an outlet for a water-containing feed stream from a boot. A flash tank is a type of separator that can be connected downstream to a separator that can operate at higher pressures.

[0020] The term "Cx" should be understood as referring to a molecule having the number of carbon atoms indicated by the subscript "x". Similarly, the term "Cx-" refers to a molecule containing less than or equal to x, and preferably x and fewer carbon atoms. The term "Cx+" refers to a molecule having more than or equal to x, and preferably x and more carbon atoms. Detailed Implementation

[0021] Single-pass washing can be used to remove oxygenated compounds from LPG streams. However, this method has significant drawbacks. A high wash water ratio is required to adequately reduce oxygenated compound concentration, leading to high operating costs and high water replenishment rates. The wash water becomes highly oxygenated, necessitating a substantial increase in the capacity of the wastewater treatment system. Oxygenated compounds also cause performance problems in the wastewater treatment unit. Oxygenated compound loss in LPG series results in the potential for lost product value.

[0022] Using adsorbent beds to further reduce the concentration of oxygenated compounds can lead to adsorbent poisoning by common oxygenated compounds in the feed, such as aldehydes. Single-pass washing is often insufficient to remove these oxygenated compounds to the levels required for economical adsorbent use. Removing oxygenated compounds from single-pass water or adsorbent regeneration streams can be expensive and energy-intensive. Even if the oxygenated compounds are extracted, their final destination can be problematic. If the stream is returned to the conversion unit, some of the oxygenated compounds may become over-accumulated.

[0023] Hydrotreating oxygenated or oxygen-rich hydrocarbon feed streams can convert oxygenated compounds into hydrocarbons. However, hydrotreating these oxygenated compounds requires a significant amount of hydrogen and generates substantial exothermic reactions in the hydrotreating reactor. Furthermore, some oxygenated compounds (such as acetaldehyde and methanol) will be hydrogenated into a series of fuel gas components rather than liquid products, thus minimizing the benefits of hydrogenation.

[0024] Other solvents, such as methanol, can be used for extraction, but they are often difficult to separate from the oxygen-containing compounds themselves due to their similar boiling points and the formation of azeotropes. Therefore, extraction schemes can incur high capital and operating costs.

[0025] We propose a solution for removing high levels of oxygenated compounds in a water scrubbing tower, followed by stripping the oxygenated compounds from the water stream. The scrubbed LPG stream can be treated to remove acidic gases, and if necessary, adsorption can occur to further remove oxygenated compounds to specified levels. The stripped water stream can be recycled back to the water scrubbing tower to reduce fresh water usage. The oxygenated compound-enriched stripper stream can then be oxidized in a thermal oxidizer to generate heat sufficient to meet energy demands. The heat supplied from the thermal oxidizer comes from a renewable source, as the oxygenated compounds are derived from bio-oil.

[0026] The proposed solution effectively removes oxygenated compounds to avoid aggregation or complication in downstream units, while eliminating wastewater generation. The calorific value of the oxygenated compounds generated by thermal oxidation can be directly used in this method or used to generate steam for other applications. This method and apparatus will enable the co-processing of well more than 5% pyrolysis oil or 10% vegetable oil in FCC units, which has been economically unfeasible until now, while maintaining low oxygenated compound content in the LPG stream.

[0027] Figure 1 The method and apparatus 10 of this disclosure are described. A petroleum feed stream is provided in a pipeline 12. The petroleum feed stream may be a liquid petroleum feed stream, such as an LPG feed stream containing at least 90% by weight of C3 and / or C4 hydrocarbons. In a mixed C3 / C4 feed stream, either component may be dominant or comprise from about 20% by weight to about 70% by weight of the mixed feed stream. The petroleum feed stream may contain other hydrocarbons, such as from about 0.5% by weight to about 3% by weight of C5 hydrocarbons.

[0028] The petroleum feed stream in line 12 can be an LPG feed stream from the FCC unit. Specifically, the LPG feed stream can include a liquid feed stream from the top receiver of the butane dehydrogenator column downstream of the top pipeline of the FCC main column downstream of the FCC riser reactor.

[0029] The petroleum feed stream in line 12 is in the liquid phase. The petroleum vapor may contain oxygenated compounds ranging from 250 Wppm to 30,000 Wppm. The petroleum feed stream loaded with oxygenated compounds is fed into water scrubber 14 so that most of the oxygenated compounds are absorbed into the water feed stream. Two water feed streams can be fed into water scrubber 14. A fresh water makeup stream can be fed into water scrubber 14 at the highest feed position in line 16. A recirculated water stream can be fed into water scrubber 14 at an intermediate feed position in line 18. The petroleum feed stream in line 12 is fed into water scrubber 14 at the lowest feed position, thus the water contacts the petroleum feed stream counter-currently. The feed positions of the fresh water stream in line 16 and the recirculated water stream in line 18 can be reversed. Water scrubber 14 can be connected downstream of the petroleum feed stream in line 12, the fresh water stream in line 16, and the recirculated water stream in line 18. A water scrubbing tower may include an internal structure that facilitates contact between water and hydrocarbon feed streams.

[0030] In water scrubbing tower 14, the water stream absorbs oxygenated compounds from the petroleum stream to produce a hydrocarbon-rich scrubbing tower overhead stream in line 20 and an oxygenated scrubbing tower bottom stream in line 22. In one embodiment, the scrubbing tower overhead stream in line 20 is oxygen-lean, containing approximately 25 W ppm to approximately 250 W ppm of oxygenated compounds, resulting in the removal of a significant amount of oxygenated compounds from the hydrocarbon phase. The concentration of oxygenated compounds in the scrubbing tower overhead stream in line 20 will depend on the concentration of oxygenated compounds in the petroleum stream in line 12.

[0031] The ratio of recirculated water stream to oil stream is typically from about 1:1 to about 3:1 (by weight), and suitably from about 3:2 to about 5:2 (by weight). The exact ratio depends on the concentration of oxygenated compounds specified by the downstream unit. The ratio of recirculated water stream to fresh water stream is typically from about 25:1 to about 100:1 (by weight). The fresh water ratio depends on the concentration of residual oxygenated compounds (especially methanol) in the recirculated water stream. The water scrubbing tower 14 can operate at temperatures from about 20°C to about 50°C and pressures from about 0.5 MPa to about 2.3 MPa.

[0032] The aqueous scrubbing column bottom stream in line 22 extends from the bottom of scrubbing tower 14 and is heated through heat exchange with the recirculated water stream in line 18. The scrubbing column bottom stream in line 22 is rich in oxygenated compounds, which must be removed to allow the water stream to be recirculated back to scrubbing tower 14. Therefore, the scrubbing column bottom stream is fed into an oxygenated stripper tower 28, which is connected downstream of the bottom line 22 from scrubbing tower 14.

[0033] In the oxygenated stripper column 28, the scrubber bottom stream in line 22 is stripped of volatile oxygenated compounds to produce an oxygen-enriched stripper top stream in the top line 30 extending from the top of the stripper column, and an oxygen-lean stripped water stream in the bottom line 32 extending from the bottom of the stripper column 28. The reboiler line 34 can be withdrawn from the bottom line 32 to reboil in the stripper reboiler 33 and returned to the stripper column 28. The recirculated stream in line 18 can also be withdrawn from the bottom line 32 and, after being cooled by heat exchange with the scrubber bottom stream in line 22 and further cooled in a recirculation cooler, pumped back to the water scrubber 14.

[0034] The water washing tower 14 can be connected downstream of the bottom line of the oxygenated stripper tower 28 to utilize the recirculated water. The oxygenated content of the recirculated water stream typically does not exceed about 2.5% by weight, and preferably does not exceed about 1% by weight. The stripper operates at low top pressure (typically about 69 kPa(g) (10 psig) to about 138 kPa(g) (20 psig)) and at a temperature of about 80°C to about 120°C, which allows low-pressure steam to be used as the heating medium in the reboiler. In one embodiment, the low-pressure steam can be generated in the thermal oxidizer unit 40 and delivered in the steam line 36 to the stripper reboiler 33 to provide the reboiler heating load.

[0035] The stripper overhead stream enriched with oxygen-containing compounds in stripper overhead line 30 can be conveyed to thermal oxidizer unit 40 for combustion of the oxygen-containing compounds. Stripper overhead line 30 may lack a condenser to retain the stripper overhead stream in the gas phase to prevent re-evaporation in thermal oxidizer unit 40. Water present in the stripper overhead line must be replenished by fresh water makeup stream in line 16. The fresh water ratio should be matched to the ratio of water lost at the top of the stripper to ensure no oxygen-rich wastewater is generated.

[0036] The stripper overhead stream in line 30 can be heated by exchanging heat with the flue gas stream in flue gas line 44 of waste heat exchanger 42, and then fed into thermal oxidizer 46. The oxygen-rich stripper overhead stream can be obtained from... Figure 2 The oxygenated compound feed streams in lines 230 and 238 of the regenerator method and apparatus 200 are supplied. The thermal oxidizer 46 may be connected downstream of the overhead line 30 of the oxygenated compound stripper column 28. A preheatable combustion air stream from line 48 and a fuel gas stream from line 50 may be supplied to the thermal oxidizer 46. The flow rate of the fuel gas stream in line 50 can be reduced or eliminated by the flow rate of the oxygenated compound from the stripper column overhead stream to the thermal oxidizer 46. The inlet temperature of the thermal oxidizer 46 is typically in the range of about 120°C to about 500°C, and the pressure is about -1 kPa(g) to about 100 kPa(g). The outlet temperature is typically in the range of about 450°C to about 1100°C, and the pressure is about -1 kPa(g) to about 50 kPa(g). The residence time in the thermal oxidizer 46 is about 0.5 seconds to about 2 seconds. Any suitable thermal oxidizer 46 may be used, including but not limited to an adiabatic thermal oxidizer chamber. The thermal oxidizer 46 may be a forced ventilation, induced ventilation, or a combination of both. The thermal oxidizer 46 may include an inline burner.

[0037] In thermal oxidizer 46, oxygen-containing compounds are oxidized to water and carbon dioxide. Hydrogen sulfide and other sulfur compounds in the thermal oxidizer feed are oxidized to sulfur oxides, including SO2 and SO3, as well as water. The flue gas stream from flue gas line 44 of thermal oxidizer 46 contains sulfur oxides (i.e., SO2 and SO3) and one or more of H2O, CO, CO2, NO2, NO, N2, and O2. The flue gas stream from flue gas line 44 is transferred to waste heat exchanger 42 for heat exchange with the oxygen-rich stream in line 30. The flue gas inlet temperature of waste heat exchanger 42 is suitably in the range of about 450°C to about 1100°C, and the pressure is about -2 kPa(g) to about 50 kPa(g). At the same pressure range, the flue gas outlet temperature is typically in the range of about 150°C to about 425°C. The flue gas stream can also be boiled in the steam line 36 through heat exchange in the heat recovery steam generator 43 to generate low-pressure steam for the stripper reboiler 33. The steam generated in the steam exchanger 43 in the line 36 can be used to... Figure 2 The reboiling line 34 and the stripper bottom steam in the regenerator reboiler 243 are reboiled. Alternatively, the flue gas can be used to directly heat the process. In another arrangement, the flue gas can be used to generate high-pressure or medium-pressure steam for output, followed by low-pressure steam for use in the process.

[0038] The flue gas stream from line 44 of waste heat exchanger 42 and / or heat recovery steam generator 43 can also be used to preheat the combustion air in quench section 52. Air in line 54 can be fed into air quench section 52 and exchange heat indirectly or directly with the flue gas stream in line 44. Air in line 54 can be directly injected into the flue gas stream in line 44 as needed to reduce the flue gas temperature. Alternatively, the combustion air stream in line 54 can exchange heat indirectly with the flue gas stream in line 44 to further cool the flue gas stream and heat the combustion air stream in line 54. The heated combustion air stream can then be conveyed in line 48 when combustion occurs in thermal oxidizer 46. The inlet temperature of the flue gas stream to quench section 52 is typically in the range of about 150°C to about 425°C, and the pressure is about -2 kPa(g) to about 50 kPa(g). The outlet temperature is typically in the range of about 150°C to about 250°C, and the pressure is from about -3 kPa(g) to about 50 kPa(g).

[0039] The quenched flue gas stream in line 56 must be treated to remove sulfur oxides. In one embodiment, a dry adsorbent is injected from line 60 into the quenched flue gas stream in line 56. The dry adsorbent may be pneumatically injected into the quenched flue gas stream. The adsorbent injected into the flue gas stream in line 56 may be fed into the dry adsorbent reactor 62 to ensure sufficient mixing residence time to achieve sufficient sulfur oxide reaction to meet the emission requirements of the final effluent gas stream, or simply to remove sufficient sulfur oxides to lower the acid dew point sufficiently or avoid complete sulfuric acid condensation in the flue gas. By lowering the sulfuric acid condensation point, more heat can be extracted from the flue gas, thus making the method more cost-effective and resulting in lower greenhouse gas emissions.

[0040] Dry adsorbents may include sodium adsorbents or calcium adsorbents. Calcium adsorbents include calcium hydroxide and can react with sulfur oxides as shown in formulas (1) and (2):

[0041] SO2 + Ca(OH)2 CaSO3·½H2O + ½H2O (1), and

[0042] SO3 + Ca(OH)2 CaSO4 + H2O (2).

[0043] Sodium adsorbents may include sodium carbonate (NaHCO3) or Trona (Na2CO3·NaHCO3·H2O). The sodium adsorbent is directly injected into the hot flue gas, where it is calcined into porous activated sodium carbonate (Na2CO3), as shown in formula (3):

[0044] NaHCO3 Na2CO3+ CO2 + H2O (3).

[0045] The thermal decomposition reaction of equation (3) occurs rapidly at elevated temperatures (such as 80°C to approximately 800°C). The resulting high surface area enables a rapid gas-solid reaction between sulfur oxides and Na₂CO₃ to form Na₂SO₄, as shown in equations (4) and (5):

[0046] Na₂CO₃ + SO₂ + ½O₂ Na2SO4 + CO2 (4), and

[0047] Na₂CO₃ + SO₃ + ½O₂ Na2SO4 + CO2 (5).

[0048] The reaction of the adsorbent and sulfur oxides in line 64 produces a sulfate-loaded flue gas stream at a temperature of about 260°C to about 343°C and a pressure of about -3 kPa(g) to about 50 kPa(g). The sulfate particles are solid and can be removed from the flue gas stream. The sulfate particles include CaSO3·½H2O, CaSO4, or Na2SO4. The flue gas stream in line 64 can be cooled to below about 220°C and fed into particulate removal section 66. The sulfate residue stream can be removed from particulate removal section 66 (e.g., via an auger in line 68) and sold as a valuable product for use in glass, detergent, or paint manufacturing.

[0049] In particulate removal section 66, sulfate is separated from the sulfate-depleted flue gas stream by fabric, steel, or ceramic filters or electrostatic precipitators. For example, a bag filter may contain filter bags that allow clean flue gas to pass through while periodically backflushing retains suspended solid particles to clean them from the filter. If high-temperature ceramic or stainless steel filters are used in particulate removal section 66, cooling the sulfate flue gas stream in line 68 may not be necessary. The flue gas stream in line 68 can then be discharged to a chimney.

[0050] If nitriles are in the oxygen-rich feed stream in the stripper tower top line 30, the thermal oxidizer 46 can convert nitriles to NOx. A NOx reduction SCR unit (not shown) can be used to react ammonia with the NOx produced in the thermal oxidizer 46 to produce molecular nitrogen and water. Any suitable NOx reduction catalyst can be used, including but not limited to: ceramic support materials, such as titanium oxide, which has an active catalytic component (such as oxides of a base metal, including TiO2, WO3, and V2O5); or activated carbon-based catalysts.

[0051] The hydrocarbon-rich scrubbing overhead stream in line 20 is oxygen-lean but still contains hydrogen sulfide and other sulfur compounds. These other sulfur compounds include carbonyl sulfides, disulfides, and methyl sulfides that cannot be extracted with water. Therefore, the scrubbing overhead stream in line 20 is introduced into sulfur removal unit 70 to remove sulfur compounds. Initially, the scrubbing overhead stream in line 20 may be introduced into acid gas removal tower 72 to absorb hydrogen sulfide from the scrubbing stream in line 20. Acid gas removal tower 72 may be connected downstream of the overhead line 20 from water scrubbing tower 14. Several different types of acid gas removal towers 72 may be used, including alkaline scrubbing units, amine treatment units, and sodium carbonate treatment units. In one exemplary embodiment, the hydrocarbon-rich scrubbing overhead stream in line 20 is scrubbed with an alkaline stream in acid gas removal tower 72. Acid gas removal tower 72 tightly mixes the hydrocarbon-rich scrubbing tower overhead stream from line 20 with the alkaline stream from line 74, wherein the alkaline stream is an aqueous alkaline solution. If the alkaline solution is sodium hydroxide, its concentration in water can be from about 5% to about 20% caustic alkali. The caustic alkali reacts with hydrogen sulfide to produce sodium hydrosulfide and sodium sulfide, both of which are soluble in water and absorbed into the alkaline stream in line 74. If removal of carbonyl sulfides is required, amines can also be added to the alkaline solution.

[0052] The desulfurization scrubbing stream containing LPG hydrocarbons in the top line 76 and the waste alkaline stream containing alkaline materials and sulfide reaction products (such as caustic soda and sodium hydrosulfide) in the bottom line 78 exit the acid gas removal tower 72. The alkali in the acid gas removal tower 72 is gradually discharged and replaced with fresh alkali. The operating conditions of the acid gas removal tower 72 are variable, but typically include ambient temperature and pressure sufficient to maintain the scrubbing stream 20 in the liquid phase. For example, temperatures ranging from about 10°C to about 60°C, and more typically from about 30°C to about 50°C, and pressures from about 500 kPa to about 1.5 MPa can be used.

[0053] If further reduction in hydrogen sulfide and sulfur concentrations is desired, the desulfurization wash stream in line 76 can be treated in extraction tower 80 to remove residual thiols by reacting any remaining thiols with an alkaline stream (such as caustic alkali) to produce thiolates. The desulfurization wash stream in line 76 is in close contact with the alkaline stream in line 82, wherein both the desulfurization wash stream in line 76 and the alkaline stream in line 82 are in the liquid phase. In one exemplary embodiment, the alkaline stream in line 82 is charged near the top of extraction tower 80, and the desulfurization wash stream in line 76 is charged near the bottom of extraction tower 80. The concentration of the alkaline stream in line 82 is variable, but typically ranges from about 10% by weight to about 20% by weight of caustic alkali in water. The aqueous alkaline stream in line 82 does not form a solution or suspension with the hydrocarbons in the desulfurization wash stream in line 76, and the alkali is heavier than the hydrocarbons in the desulfurization wash stream 76. Therefore, as the hydrocarbons in the desulfurized washed feed stream in line 76 flow upward through extraction tower 80, the alkali flows downward through extraction tower 80. In one embodiment, extraction tower 80 includes multiple trays configured to guide the heavier alkali feed stream in line 82 downward through a tortuous path, while guiding the desulfurized washed feed stream in line 76 upward through a tortuous path, and the trays are designed to tightly mix and bring the two streams into contact when they flow countercurrently. In another embodiment, extraction tower 80 includes packing or other structures to mix the alkali and hydrocarbons as they flow through each other. The extraction tower 80 is sized to provide sufficient stages for the mercaptan to react with the alkali, such as about 2 to about 6 stages or more. Exemplary operating conditions for extraction tower 80 include temperatures from about 10°C to about 50°C and pressures sufficient to keep the washed feed stream in the liquid phase, such as about 500 kPa to about 1.5 MPa.

[0054] The thiolate-rich aqueous alkaline stream in bottom line 86 exits extraction tower 80 and contains an aqueous alkaline solution and thiolates. An oxygen supply stream from line 90 is added to the alkaline-rich stream in line 86 to react with the thiolates. In one exemplary embodiment, the oxygen supply stream 90 is air, but other oxygen-containing gases may also be used. Oxygen and water react with the thiolates in thiol oxidizer 94 to form disulfides and alkali. The unassisted reaction rate is slow, and therefore an oxidation catalyst in line 96 is used to accelerate the oxidation reaction that produces disulfides, and the oxidation catalyst in line 96 is added to the alkali recycling system as needed. In one exemplary embodiment, the oxidation catalyst in line 96 is added to the alkaline-rich stream in line 86 upstream of thiol oxidizer 94, but the oxidation catalyst in line 96 may also be added at other locations. Wash oil may also be added to line 86 to help separate alkali and hydrocarbons, thereby minimizing the disulfide content in the lean alkaline stream in line 82.

[0055] The oxidation catalyst in line 96 can be a metal chelate and can be in liquid or solid form. Several chelating agents can be used, such as phthalocyanine, tetraphenylporphyrin, or tetraphyidinoporphyrazine. Many chelating agents are not readily soluble in water, but their water solubility can be increased by bromination, sulfonation, or carboxylation. The metal is one or more of iron, cobalt, manganese, molybdenum, or vanadium. In some embodiments, a water-soluble oxidation catalyst is used in line 96; however, the insoluble form of the oxidation catalyst in line 96 can be used in suspension or loaded onto a substrate held in a fixed position in the thiol oxidizer 94 or held in a slurry with the alkaline feed stream. Suitable substrates include activated carbon, charcoal granules, thermoplastic polymers, ion exchange resins, and a variety of other materials. One exemplary oxidation catalyst in line 96 is iron tetrasulfonate phthalocyanine, but many other embodiments of the oxidation catalyst are possible.

[0056] The alkaline feed stream (including thiols) in line 86, oxygen from the oxygen supply stream in line 90, and the oxidation catalyst in line 96 are heated and fed into the mercaptan oxidizer 94. The mercaptan oxidizer 94 includes a packed bed 93, trays, or other structures that maintain thorough mixing of the aqueous alkaline solution and water-insoluble disulfides as the alkali flow passes through. The thiols are oxidized to disulfides, so that substantially no thiols remain in the mixed alkaline / disulfide feed stream exiting the top of the mercaptan oxidizer 94 in line 98. Exemplary operating conditions for the mercaptan oxidizer 94 include pressures of approximately 200 kPa to approximately 500 kPa (gauge pressure) and temperatures of approximately 30°C to approximately 60°C. If necessary, the alkaline feed stream in line 82 is supplemented with fresh alkali in line 97. The fresh alkaline feed stream in line 97 can be added at various locations, including but not limited to the alkaline feed stream in line 86 upstream of the mercaptan oxidizer 94 as illustrated.

[0057] The mixed alkaline / disulfide stream in line 98 exits the mercaptan oxidizer 94 and enters the disulfide separator 100. The disulfide separator 100 has no agitation and sufficient volume to allow the separation of water-insoluble disulfides from the aqueous alkaline solution. The mercaptan oxidizer 94 and the disulfide separator 100 work together to regenerate the alkali and are fluidly coupled to the extraction tower 80. In one exemplary embodiment, the disulfide separator 100 has a residence time of approximately 0.5 hours to approximately 3 hours. Any excess gas (such as excess nitrogen or oxygen from the oxygen supply stream in line 96) is discharged from the disulfide separator 100 in exhaust line 102. Exhaust line 102 may be directed to a scrubber or other contamination control device and may optionally include a liquid entrainment separator (not illustrated) to prevent the discharge of alkali or disulfides. The density of disulfide oil is less than that of alkali; therefore, the upper layer of disulfide oil exits near the top of disulfide separator 100 in the disulfide stream in the top line 104, while the alkaline stream in line 82 is recovered near the bottom of disulfide separator 100. The alkaline stream in line 82 contains a small amount of carried disulfides, which enter the extraction tower 80 in the alkaline stream of line 82. The carried disulfides are then combined with the hydrocarbons exiting the extraction tower 80, as disulfides are more soluble in nonpolar hydrocarbons than in polar alkaline solutions.

[0058] Thiols are removed from the desulfurization wash stream in line 76 in extraction tower 80, and hydrocarbons in the desulfurization wash stream in line 76 exit extraction tower 80 in the treated wash stream in overhead line 84. The hydrocarbons in the treated wash stream in line 84 also contain low concentrations of disulfides from the recovered alkaline stream in line 82. If the treated wash stream in overhead line 84 containing LPG hydrocarbons contains oxygenated compounds exceeding specified levels, or if significant nonpolar oxygenated compounds (such as ethers) are present, the treated wash stream can be transferred to oxygenated compound adsorption unit 110 to remove residual oxygenated compounds remaining in the wash stream from line 20. Residual disulfides in the treated hydrocarbon stream in line 84 are typical.

[0059] The oxygenated compound adsorption unit 110 includes an oxygenated compound adsorbent bed 112 connected downstream of the overhead line of the water scrubbing tower 14. The adsorbent in the adsorbent bed can be an alkali metal aluminosilicate capable of removing oxygenated compounds to trace levels. The alkali metal can be sodium. A suitable adsorbent is ORG-EMOLSIV, available from UOP LLC (Des Plaines, Illinois). The oxygenated compound adsorbent bed removes oxygenated compounds to concentrations below about 2 wppm to about 30 wppm. Furthermore, the adsorbent can adsorb oxygenated compounds such that no single oxygenated compound can have a concentration greater than about 1 wppm to 8 wppm. An oxygenated compound-depleted LPG feed stream can be provided in the line 114 exiting the oxygenated compound adsorption unit 110. The oxygenated compound adsorption unit 110 can operate at temperatures ranging from about 30°C to about 50°C and pressures ranging from about 500 kPa to about 1.5 MPa. The oxygen-depleted LPG stream in pipeline 114 is the final LPG product stream with oxygen-containing compounds removed. It can be further processed to separate the components into valuable products without concern for oxygen-containing impurities.

[0060] Figure 2 A method for regenerating adsorbent bed 110 is provided, which is not shown. Figure 1 The connection is made so that when the oxygen-containing compound adsorbent bed 112 in the oxygen-containing compound adsorption unit 110 is used up, it is connected to the oxygen-containing compound adsorption unit 110 via a valve. Figure 1 The method and apparatus 10 disconnects line 84 to take it offline for regeneration, and LPG is discharged from adsorbent bed 112 to LPG buffer tank 115 below line 114 to ensure minimal LPG loss, and is connected to an appropriate valve. Figure 2 The regeneration method and apparatus 200. Another adsorbent bed (not shown) can be connected to Figure 1 Pipeline 84 continues the process of removing oxygen-containing compounds from LPG.

[0061] exist Figure 2 In this process, the regenerant is pumped into process and equipment 200 via line 202. The regenerant may contain an aliphatic hydrocarbon, preferably a straight-chain hydrocarbon, having 5 to 8 carbon atoms per molecule. n-Hexane is a suitable regenerant. Fresh replenishment of regenerant can be provided via line 203.

[0062] The regenerant in line 202 is pumped to cooling line 204, heating line 206, or standby line 226. Figure 2The implementation includes three main regeneration "modes". In the heating mode, the regenerant flows through heat exchangers 210, 212, and 214 before reaching adsorption unit 110, while lines 204 and 226 are blocked by valves on them. In the cooling mode, the regenerant flows through cooler 208 before reaching adsorption unit 110, while lines 206 and 226 are blocked by valves on them. In the standby mode, the regenerant flows through line 226 back to regenerant receiver 224, while lines 204 and 206 are blocked by valves on them. As the regeneration cycle proceeds, all flow is diverted to one of these three paths.

[0063] The first stage of regeneration is the thermal regenerator stage. An open valve on heating line 206 directs the regenerator to the feed heater on heating line 206, while a valve on line 204 is closed. Three feed heaters can be provided, which, in downstream order, include regenerator evaporator 210, regenerator superheater 212, and electric superheater 214. Feed heaters 210, 212, and 214 evaporate the regenerator and superheat it to approximately 260°C (500℉) to approximately 316°C (600℉). A temperature sensor in the adsorbent bed 112 senses the temperature and compares it to a setpoint. If the temperature is below the setpoint, the electric superheater 214 provides additional load. If the temperature is above the setpoint, the load on the electric superheater 214 is reduced.

[0064] The regenerant from heating line 206 is fed into the waste adsorbent bed 112 in adsorption unit 110 via regenerant feed line 215 to desorb oxygen-containing compounds into the regenerant stream for complete regeneration of the oxygen-containing adsorbent. During regeneration, adsorbent unit 110 operates at approximately 260°C (500℉) to approximately 316°C (600℉) and pressures of approximately 200 kPa and approximately 500 kPa. The hot regenerant stream rich in desorbed oxygen-containing compounds exits adsorption unit 110 in the hot discharge line through an open valve on hot discharge line 216, while a valve on cold discharge line 218 is closed. The hot regenerant rich in oxygen-containing compounds is cooled in adsorbent cooler 220 and enters regenerant receiver 224, which may be an air cooler and possibly a temperature-controlled cooler 222.

[0065] After the adsorbent bed is regenerated in the hot regenerator stage, a cooling stage is initiated. The regenerator flow in line 202 is directed through cooling line 204 and to regenerator feed cooler 208, while the valve on heating line 206 is closed. In this way, the bed is cooled by approximately 30°C to approximately 50°C. After cooling, high-pressure nitrogen from line 250 is fed into adsorbent unit 110 to discharge the regenerator from adsorbent bed 112. The regenerator is stored in hexane buffer tank 252 to prevent material loss. LPG may then be slowly introduced into adsorbent bed 112 from LPG buffer tank 115 in line 116 until exothermic reactions are minimized. Adsorbent bed 112 is then considered regenerated and can be brought back online by connecting adsorbent unit 110 to line 84 (possibly in a hysteresis configuration).

[0066] In standby mode, the regenerant in line 202 can also bypass adsorption unit 110 in line 226 and enter regenerant receiver 224 after being cooled in overflow cooler 228. Standby mode can be operational when adsorbent bed 112 is in regeneration and adsorption operation.

[0067] The regenerator receiver 224 separates the hydrocarbon phase from the aqueous phase in the dried regenerator stream in the top pipeline 228, the aqueous phase containing oxygenated compounds desorbed from the adsorbent bed 112 in the oxygenated water stream in the bottom pipeline 230. It is also used to separate nitrogen from the regenerator in the discharge step. The oxygenated water stream in the bottom pipeline 230 can be conveyed to… Figure 1 The thermal oxidizer unit 40 is used for the combustion of oxygen-containing compounds. This ensures that no oxygen-rich wastewater stream is generated during normal operation, thereby minimizing the impact on the existing infrastructure. The dried regenerant stream in the top pipeline 228 is fed into the regenerant tower 232. The regenerant receiver 224 operates at approximately 50°C (122℉) to approximately 80°C (176℉) and pressures of approximately 25 kPa and approximately 150 kPa.

[0068] The regenerator tower 232 is downstream of the oxygen-containing adsorbent bed 112 of the adsorption unit 110 during the regeneration cycle. In the regenerator tower 232, oxygen-containing compounds are vaporized from the dried regenerator stream in the regenerator receiver tower top line 228. The hydrocarbon regenerator stream in the regenerator tower top line 233 is condensed in the regenerator condenser 234 and separated in the regenerator receiver 236 to generate a regenerator waste gas stream in the net tower top line 238 and a reflux stream returning to the tower. The regenerator waste gas stream in the net tower top line 238 contains residual regenerator and oxygen-containing compounds and can be fed via line 30 to… Figure 1The thermal oxidizer 40 is located within the regenerator. The deoxidizing regenerator stream in the bottom line 240 of the regenerator tower can be split between the reboiling stream in line 241 and the recirculated regenerator stream in line 242. The reboiling stream is reboiled in the regenerator reboiler 243 and returned to the tower, while the recirculated regenerator stream is recirculated to the regenerator line 202 and pumped back into the process. The reboiler 243 can be heated by steam from the thermal oxidizer unit 40.

[0069] In one embodiment, the petroleum feed stream can be depropanized to separate C3 hydrocarbons from C4 hydrocarbons, allowing each stream to be washed individually in a dedicated washing tower. If most oxygen-containing compounds are enriched in either stream, this embodiment can be operated to reduce the water rate to the washing tower. In such embodiments, the bottom stream of the washing tower can be processed together in the disclosed methods and apparatus. However, the top C3 and C4 streams from each washing tower may be treated separately in a repetitive process to maintain the separation of C3 and C4 hydrocarbons. Furthermore, any H2S in the feed will be enriched in the C3 fraction, allowing for different metallurgical possibilities.

[0070] The aforementioned method and apparatus provide an efficient way to remove oxygen-containing compounds from light hydrocarbon streams without generating large amounts of wastewater that must be treated. In fact, no wastewater requiring treatment is generated from method and apparatus 10.

[0071] Example

[0072] The methods and apparatus disclosed herein simulate an LPG stream generated by co-processing the following feed and VGO in an FCC unit. Table 1 provides the oxygenated compound concentrations in the LPG feed to the scrubbing tower, Table 2 provides the oxygenated compound concentrations in the scrubbed LPG stream from the scrubbing tower, Table 3 provides the oxygenated compound concentrations in the recirculated water stream from the oxygenated compound stripper tower, and Table 4 provides the oxygenated compound concentrations from the adsorption unit. Concentrations are expressed in wppm.

[0073] Table 1. Concentration of LPG in feed to the water washing tower

[0074]

[0075] Table 2. Concentration of LPG from the water washing tower

[0076]

[0077] Table 3. Concentration of recirculated water in the scrubbing tower

[0078]

[0079] Table 4. Concentration from the adsorption unit

[0080]

[0081] The remaining total oxygen-containing compounds are mainly ethers, with the remainder being other compounds.

[0082] Specific implementation plan

[0083] While the following description is presented in conjunction with specific embodiments, it should be understood that the description is intended to be illustrative and not to limit the scope of the foregoing description and the appended claims.

[0084] A first embodiment of the present invention is a method for removing oxygen-containing compounds from a petroleum feed stream of C3 and / or C4 hydrocarbons, the method comprising: absorbing oxygen-containing compounds from the petroleum feed stream into a water feed stream to produce a hydrocarbon-rich scrubber overhead stream and an oxygen-rich scrubber bottom stream; and stripping the scrubber bottom stream to produce an oxygen-enriched stripper overhead stream and an oxygen-lean stripped water stream. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, wherein the petroleum feed stream includes fluid cracking products. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising recycling the stripped bottom stream as a water stream. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising feeding makeup water into the absorption step. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising oxygen-containing compounds in the thermal oxidation stripper overhead stream. One embodiment of the invention comprises one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, recovering energy via exchange with the method or steam generated. One embodiment of the invention comprises one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising removing hydrogen sulfide from the scrubbing tower overhead stream. One embodiment of the invention comprises one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising removing nitriles from the scrubbing tower overhead stream. One embodiment of the invention comprises one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising adsorbing residual oxygen-containing compounds from the scrubbing tower overhead stream. One embodiment of the invention comprises one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising absorbing hydrogen sulfide with an alkaline solution to provide a desulfurization scrubbing stream; and oxidizing mercaptans from the desulfurization scrubbing stream. One embodiment of the invention comprises one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further comprising charging the stripper overhead stream to the thermal oxidation step without condensation. One embodiment of the invention, which is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further includes injecting a dried adsorbent to adsorb sulfur oxides from the flue gas from the thermal oxidation step, thereby increasing the possibility of recovering heat from the effluent. Another embodiment of the invention, which is one, any, or all of the embodiments described in the preceding embodiments to the first embodiment of this paragraph, further includes regenerating the adsorbent loaded with residual oxygen-containing compounds using an alkane feed comprising 5 to 8 carbons.One embodiment of the present invention is one, any, or all of the embodiments from the previous embodiments to the first embodiment of this paragraph, and further includes heat exchange between the bottom stream of the washing tower and the bottom stream of the stripped tower.

[0085] A second embodiment of the present invention is an apparatus for removing oxygenated compounds from an oil stream, the apparatus comprising: a water scrubbing tower connected to the oil stream and a water stream; an oxygenated compound stripping tower connected downstream of a bottom line from the water scrubbing tower; and an acid gas removal tower connected downstream of a top line from the water scrubbing tower. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding to the second embodiment of this paragraph, further comprising a thermal oxidizer connected downstream of the top line of the oxygenated compound stripping tower. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding to the second embodiment of this paragraph, wherein the water scrubbing tower is connected downstream of the bottom line of the oxygenated compound stripping tower for recirculating water. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding to the second embodiment of this paragraph, further comprising an oxygenated compound adsorbent bed connected downstream of the top line of the water scrubbing tower. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding embodiments to the second embodiments described in this paragraph, and further includes a regenerator tower in communication with the downstream of the oxygen-containing adsorbent bed during the regeneration cycle.

[0086] A third embodiment of the present invention is a method for removing oxygen-containing compounds from a petroleum feed stream of C3 and / or C4 hydrocarbons. The method includes: absorbing oxygen-containing compounds from the petroleum feed stream into a water feed stream to produce a hydrocarbon-rich scrubber overhead stream and an oxygen-rich scrubber bottom stream; stripping the scrubber bottom stream to produce an oxygen-rich stripper overhead stream and an oxygen-lean stripped bottom stream; and recycling the stripped bottom stream as a water feed stream to the absorption step. One embodiment of the present invention is one, any, or all of the embodiments described in the preceding to the third embodiment of this paragraph, further including oxygen-containing compounds in the thermal oxidation stripper overhead stream. Although no further detailed description is provided, it is believed that those skilled in the art can make various changes and modifications to the present disclosure and adapt it to various uses and conditions by utilizing the foregoing description to its fullest extent and by readily identifying the essential features of the disclosure without departing from its spirit and scope. Therefore, the foregoing preferred specific embodiments should be understood as illustrative only and not as limiting the remainder of this disclosure in any way, and are intended to cover various modifications and equivalent arrangements included within the scope of the appended claims.

[0087] In the foregoing, all temperatures are expressed in degrees Celsius, and all portions and percentages are by weight unless otherwise specified.

Claims

1. A method for removing oxygen-containing compounds from a petroleum feed stream of C3 and / or C4 hydrocarbons, the method comprising: Oxygen-containing compounds from the petroleum feed stream are absorbed into the water feed stream to produce a hydrocarbon-rich scrubbing tower top stream and an oxygen-rich scrubbing tower bottom stream. as well as The stripping process produces a stripper top stream enriched with oxygen-containing compounds and a stripped water stream leaning against oxygen-containing compounds.

2. The method according to claim 1, wherein the petroleum feed stream comprises fluid cracking products.

3. The method according to claim 1, further comprising recycling the stripped bottom feed stream as the water feed stream.

4. The method according to claim 1, further comprising feeding supplemental water into the absorption step.

5. The method according to claim 1, further comprising thermally oxidizing oxygen-containing compounds in the stripper tower overhead stream.

6. The method of claim 5, wherein the method recovers energy via an exchange with the steam generated by the method.

7. The method according to claim 1, further comprising removing hydrogen sulfide from the top stream of the scrubbing tower.

8. The method according to claim 1, further comprising removing nitrile from the top stream of the scrubbing tower.

9. An apparatus for removing oxygen-containing compounds from a petroleum stream, the apparatus comprising: A water washing tower, wherein the water washing tower is connected to the oil feed stream and the water feed stream; An oxygenated compound stripping tower, wherein the oxygenated compound stripping tower is connected downstream of the bottom pipeline from the water washing tower; and An acid gas removal tower is connected downstream of the top pipeline from the water washing tower.

10. The apparatus of claim 9, further comprising a thermal oxidizer connected downstream of the top pipeline of the oxygenated stripper tower.

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