Direct Desulfurization System and Method

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Application No. 63/528,989 filed on Jul. 26, 2023, which application is incorporated herein by reference as if reproduced in full below.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND OF THE INVENTION

Many hydrocarbon-containing fluids, including naturally occurring gas streams such as sub-surface natural gas, contain sulfur compounds, including hydrogen sulfide (H₂S). Governmental regulations limit plant emissions of sulfur-bearing gases. Refineries commonly include sulfur reduction units to decrease emissions of sulfur compounds.

The use of a Claus catalytic reaction is widely known in the field and commonly used in sulfur recovery units. Many currently practiced Claus processes consists of a thermal stage and a catalytic stage. In the thermal stage, a waste gas containing hydrogen sulfide is injected into a thermal reactor where hydrogen sulfide is partially oxidized with air at high temperatures to form a quantity of sulfur dioxide. The thermal reaction further serves to oxidize ammonia. Combustion gases are cooled in a waste heat boiler in which a portion of the hydrogen sulfide reacts with sulfur dioxide to form water and elemental sulfur. The elemental sulfur is condensed and removed. One such system is described in U.S. Pat. No. 7,250,149 to Smith, which is incorporated by reference herein in its entirety to the extent non inconsistent herewith. In another sulfur removal process based on the Claus reactor, sulfur dioxide (SO₂) is introduced into the process stream at determined locations during a multiple stage reactor process, as disclosed in U.S. Pat. No. 8,795,625 to Smith, which is incorporated by reference herein in its entirety to the extent non inconsistent herewith.

While there exists utility in these systems, they each possess certain drawbacks and/or undesirable features. A need therefore exists for an improved sulfur removal system for natural gas streams and the like.

BRIEF SUMMARY OF THE INVENTION

Embodiments of a desulfurization system of the present invention generally include a series of components designed to utilize an input of fluid comprising hydrogen sulfide as an impurity, such as a refinery fuel gas stream, and an input of a gaseous stream comprising sulfur dioxide, whereby the combined streams progress through the individual components such that within one or more such components molecular sulfur (S₂) created within the system, in molten form, is removable therefrom. In one aspect, embodiments of a desulfurization system of the present invention function such that the SO₂ reacts with the H₂S to form the S₂ and thereby purify the fluid by diminishing the amount of the H₂S present therein.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present invention, reference is now made to the accompanying drawing, in which:

FIG. 1 is a depiction of an embodiment of a direct desulfurization system of the present invention.

FIG. 2 is a depiction of an embodiment of a direct desulfurization system of the present invention that includes post-desulfurization equipment.

FIG. 3 is a depiction of another embodiment of a direct desulfurization system of the present invention that includes post-desulfurization equipment.

DETAILED DESCRIPTION OF EXEMPLARY EMBODIMENTS OF THE INVENTION

The exemplary embodiments are best understood by referring to the drawings, like numerals being used for like and corresponding parts of the various drawings. In the following description of embodiments, orientation indicators such as “top,” “bottom,” “up,” “down,” “upper,” “lower,” “front,” “back,” etc. are used for illustration purposes only; the invention, however, is not so limited, and other possible orientations are contemplated.

Referring to FIG. 1, therein is depicted an embodiment of a direct desulfurization system 100 of the present invention. In this embodiment, a direct desulfurization system 100 comprises a mixing vessel 2. In one embodiment, a mixing vessel 2 may comprise any useful size, shape, dimensions or internal mixing features for combining a gas stream with a liquid stream, as would be understood by one skilled in the art. In one embodiment, a direct desulfurization system 100 comprises a (first) heating vessel (reheater) 4, a (first) reactor 6 and a (first) condenser 8. In one aspect, the section of an embodiment of a direct desulfurization system 100 comprising a reheater, a reactor and a condenser constitutes a desulfurization zone 22. In the embodiment depicted in FIG. 1, direct desulfurization system 100 comprises additional desulfurization zones 22, namely, a second reheater 10, a second reactor 12 and a second condenser 14, as well as a third reheater 16, a third reactor 18 and a third condenser 20, although the invention is not so limited and a direct desulfurization system 100 may comprise a single desulfurization zone 22 or any useful number of desulfurization zones 22.

In one embodiment, a reheater 4, 10 and/or 16 may comprise a vessel adapted and configured to adequately heat the process stream (not separately labeled) flowed thereinto. In one embodiment, a reactor 6, 12 and/or 18 may comprise a vessel adapted and configured to effect the catalyzed reaction between H₂S and SO₂ whereby S₂ and H₂O are produced, in accordance with the chemical reaction stoichiometry shown below:

In one embodiment, a reactor of the present invention comprises a conventional Claus catalytic reactor, as would be understood by one skilled in the art, although the invention is not so limited and other types of catalytic reactors may be employed. In one embodiment, a condenser 8, 14 and/or 20 may comprise a separation vessel adapted and configured to provide for the condensation of S₂ and separation thereof from the remainder of the process stream, as would be understood by one skilled in the art.

Referring now to FIG. 2, in one embodiment a direct desulfurization system 100 may comprise a “back-end” system 24 which may be utilized to further process the fluid stream. In one embodiment, the back-end system 24 may be fluidly connected to the final condenser in the series of components that constitutes the desulfurization system 100, although the invention is not so limited and the back-end system 24 may be otherwise fluidly connected to the desulfurization system 100 and/or fluidly connected to two or more components of the desulfurization system 100.

In one embodiment, a back-end system 24 comprises a heater (pre-heater) 26, a hydrogenation reactor 28, a cooler 30 and a contacter (i.e., mixing device providing for physical contact and interaction of fluids) 32. In one embodiment, a pre-heater 26 may comprise a vessel adapted and configured to adequately heat the process stream 40 flowing from the desulfurization system 100. In one embodiment, a hydrogenation reactor 28 may comprise a vessel adapted and configured to mix an input stream comprising hydrogen gas (H₂) (not shown) with the heated desulfurization system 100 output stream 40. In one embodiment a hydrogenation reactor 28 may comprise an existing refinery hydrogenation reactor, although the invention is not so limited and other types and/or purposed hydrogenation reactors may be employed. In one embodiment a cooler 30 may comprise a vessel adapted and configured to cool the fluid stream exiting the hydrogenation reactor 28. In one embodiment (not shown), a back-end system 24 may comprise a quench tank, in additional to, or in lieu of, a cooler 30, as would be understood by one skilled in the art. In one embodiment, a contacter 32 comprises a vessel adapted and configured to separate the fluid gas stream into an overhead gas stream 34 and a bottoms liquid stream 36. In one embodiment, a back-end system 24 comprises a contacter inlet line 38 that directs liquid from an external source (now shown) into the contacter 32.

In another embodiment, depicted in FIG. 3, a back-end system 24A comprises one or more cold bed absorbers 48. In the embodiment shown in FIG. 3, two cold bed absorbers 48A and 48B are utilized. In one embodiment, fluid output stream 40 is first only directed to cold bed absorber 48A, wherein that cold bed absorber is operated below the dew point of sulfur (˜250° F. to ˜300° F.), and sulfur contained in fluid output stream 40 is deposited as S₂ therein. In one embodiment, during this operational step, the fluid contained within fluid output stream 40 that makes it past the cold bed absorber (without being deposited as S₂) flows through cold bed absorber 48A drain piping 49A and enters cold bed absorber fluid output stream 50. In one embodiment, the S₂ may be deposited in pores within a catalyst contained within the cold bed absorber 48A, i.e., the “bed,” as would be understood by one skilled in the art. This process continues until a desired amount of S₂ has been deposited. In one aspect, such determination can be made through monitoring of deactivation of the catalyst. At this time, the fluid output stream 40 is diverted to cold bed absorber 48B to undergo similar processing. In one embodiment (not shown), a vessel may be provided between one or more of the cold bed absorbers 48 and the cold bed absorber fluid output stream 50, i.e., along drain piping 49A and/or 49B, to collect fluid from one cold bed absorber 48 while S₂ is being collected from the other cold bed absorber 48.

In one embodiment, once the flow of fluid output stream 40 is diverted to cold bed absorber 48B, a hot gas is passed through the cold bed absorber 48A, thereby vaporizing the S₂ contained there within and flowing it into cold bed absorber fluid output stream 50. Therein, the fluid is introduced to a cold bed absorber condenser 52 in fluid communication with cold bed absorber fluid output stream 50, and liquid S₂ is diverted therefrom as another S₂ output stream 46. In one embodiment, the cold bed absorbers 48A, 48B are operated alternatively in this fashion to continuously process fluid output stream 40, as would be understood by one skilled in the art.

Any fluid contained within cold bed absorber fluid output stream 50 that does not condense within cold bed absorber condenser 52 (and therefore exit via the accompanying S₂ output stream 46) flows into one or more crystallizers 54. In the embodiment shown in FIG. 3, crystallizers 54A and 54B are utilized. In one embodiment, a crystallizer 54 may comprise an exchanger whereby, similar to the process that occurs with the cold bed absorbers 48, the crystallizer 54 is operated alternatively in a “cold” mode (i.e., below the dew point of sulfur) and “hot” mode. In one embodiment, temperature control of a crystallizer 54 may be maintained via introduction of a hot fluid (e.g., steam) and a cold fluid (e.g., chilled water), (neither shown in FIG. 3). When the crystallizer 54 is being operated in the cold mode, any sulfur entering the crystallizer 54 is deposited therein as S₂. In the hot mode, any solid S₂ in the crystallizer is liquidized and flows though crystallizer drain piping 55A or 55B into crystallizer fluid output stream 56. Thereupon, the liquidized S₂ is introduced to a crystallizer condenser 58 in fluid communication with crystallizer fluid output stream 56, and S₂ is diverted therefrom as another S₂ output stream 46. In one embodiment, the crystallizers 54A, 54B are operated alternatively in this fashion to continuously process cold be absorber fluid output stream 56, as would be understood by one skilled in the art. In one embodiment (not shown), a vessel may be provided between one or more of the crystallizers 54 and the crystallizer fluid output stream 56, i.e., along drain piping 55A and/or 55B, to collect fluid from one crystallizer 54 while S₂ is being collected from the other crystallizer 54.

Although the embodiment of back-end system 24A includes both one or more cold bed absorbers and one or more crystallizers, the embodiment is not so limited an in other embodiments (not shown), a back-end system 24A may comprise only one or more cold bed absorbers or one or more crystallizers. In addition, in an embodiment of a back-end system 24A (not shown), the sequence of the cold bed absorber(s) operationally preceding the crystallizer(s) can be reversed.

Still referring to FIG. 3, in one embodiment back-end system 24A comprises a quench tower 60. In one embodiment, a quench tower 60 may be provided to remove any remaining SO₂ in the gas stream by circulating a slightly basic stream therethrough. In one embodiment NaOH may be employed therefor. In this manner, the SO₂ can be removed without removing CO₂ or H₂S, as would be understood by one skilled in the art. In one embodiment shown in FIG. 3, this quench system (not separately numbered) comprises a quench tower 60, a circulating pump 62, a heat exchanger 64 and a filter 66. In one embodiment, the circulation loop comprises a waste output line 68, an overhead output line 70 and a base input line 72, as would be understood by one skilled in the art. In one aspect, the total dissolved solids may be controlled by purging some of the circulating solution and making up with fresh water. To maintain a pH>7 of the circulating water, a base such as NaOH may be added. A filter 66 on the circulating water stream can remove the remaining sulfur vapor that will be solidified when it is contacted with the water stream. In one embodiment, fluid flowing out of waste output line 68 can be treated as waste and fluid flowing out of overhead output line 70 may be further processed (not shown).

Operation

In operation, an embodiment of a desulfurization system 100, two fluid streams are combined in a mixing vessel 2. In one aspect, a mixing vessel 2 may comprise any useful mixing component(s) and/or mixing technology that can be configured and adapted to thoroughly mix the tow fluid streams, as would be understood by one skilled in the art. In one embodiment, a first stream 42 comprises a hydrocarbon and, as an impurity, hydrogen sulfide. In one embodiment, the first fluid stream 42 consists substantially of a gas, such as, but not limited to, natural gas. In one embodiment, the gas comprises a refinery fuel gas stream, although the invention is not so limited and other gas streams may be employed. In one embodiment, the first gas stream is supplied to the mixing vessel 2 under a pressure of about 60-100 psig, although other gas supply pressures may be employed. In one embodiment, the first gas stream 42 is supplied to the mixing vessel 2 at a temperature of about 75-150° F., although the invention is not so limited and other first stream 42 temperatures may be employed. In one embodiment, the first gas stream 42 may comprise about five percent hydrogen sulfide, although the invention is not so limited and the first stream 42 may comprise other concentrations of hydrogen sulfide.

In one embodiment, a second stream 44 comprises gaseous sulfur dioxide. In one embodiment, the sulfur dioxide stream 44 may originate in an SO₂ production unit, although any sulfur dioxide source(s) may be utilized. In one embodiment, the second gas stream is supplied to the mixing vessel 2 under a pressure of about 60-100 psig, although other gas supply pressures may be employed. In one embodiment, the second gas stream 44 is supplied to the mixing vessel 2 at a temperature of about 120-300° F., although the invention is not so limited and other second stream 44 temperatures may be employed.

In one embodiment, the combined streams 42 and 44 are mixed within mixing vessel 2 and then the mixed fluid stream is flowed therefrom into a first desulfurization zone 22 which comprises a first reheater 4, a first reactor 6 and a first condenser 8. In one embodiment, this entails flow of the mixed fluid stream output of mixing vessel 2 being directed to the first reheater 4. In one embodiment, the reheater 4 heats the mixed fluid stream to about 550° F., although other reheating temperature profiles may be employed. In one embodiment, the fluid stream output of the first reheater 4 is directed to the first Claus catalytic reactor (converter) 6. In one aspect, the reheater 4 is operated such that the temperature in the converter 6 is maintained about 30° F. above the sulfur dew point to prevent temporary deactivation of the Claus reactor catalyst.

In one embodiment, the output fluid stream of the first converter 6 is maintained at about 600° F. as it is flowed into the first condenser 8, although other converter temperature profiles may be employed. In one embodiment, the fluid stream is cooled within the condenser 8 to about 300-310° F., although other condenser temperature profiles may be employed. In one embodiment, a liquid (molten) sulfur output stream 46 flows from the first condenser 8 and the S₂ thus obtained may be handled as desired, as would be understood by one skilled in the art.

In one embodiment, as depicted in FIG. 1 and described below, a desulfurization system 100 may comprise a series of three desulfurization zones 22, but the invention is not so limited and in other embodiments (not shown) a desulfurization system 100 may comprise any configuration employing one or more desulfurization zones 22. Factors which may influence the number of desulfurization zones 22 employed include, but are not limited to, the composition of the hydrocarbon input stream 42, purity of the SO₂ input stream 44 and the desired removal efficiency of the desulfurization system 100, as would be understood by one skilled in the art.

In one embodiment the fluid stream exiting the first condenser 4 is directed to a second reheater 10 wherein it is heated to about 460° F., although other reheating temperature profiles may be employed. In one embodiment, the fluid stream exiting the second reheater 10 is directed to a second converter 12, wherefrom it exits at about 470° F., (although other converter temperature profiles may be employed) and is directed to a second condenser 14. In one embodiment, the fluid stream is cooled to about 300-310° F. by the second condenser 14, although other condenser temperature profiles may be employed. In one embodiment, a liquid (molten) sulfur output stream 46 flows from the second condenser 14 and the S₂ as described above with regard to the first condenser 8.

In one embodiment, the fluid stream exiting the second condenser 14 is directed to a third reheater 16 wherein it is heated to about 400° F., although other reheating temperature profiles may be employed. In one embodiment, the fluid stream exiting the third reheater 16 is directed to a third converter 18, wherefrom it exits at about 410° F., (although other converter temperature profiles may be employed) and is directed to a third condenser 20. In one embodiment, the fluid stream is cooled to about 270° F. by the third condenser 20, although other condenser temperature profiles may be employed. In one embodiment, a liquid (molten) sulfur output stream 46 flows from the third condenser 14 and the S₂ as described above with regard to the first condenser 8 and second condenser 14. In one embodiment, a substantially desulfurized fluid stream 40 exits from the third condenser 20, which, as described below regarding FIG. 2, may be further manipulated. In embodiment, the desulfurization system 100 can remove about 98% of the H₂S introduced thereto.

In one embodiment, a desulfurization system 100 comprising a back-end system 24 may be operated such that the fluid stream 40 exiting the third condenser 20 is directed to a pre-heater 26, wherein it is heated to about 450° F., although other pre-heating temperature profiles may be employed. In one embodiment, the fluid stream exiting the pre-heater 26 is directed to a hydrogenation reactor 28. In one embodiment, a hydrogen source (not shown) flows hydrogen gas (H₂) into the hydrogenation reactor 28 wherein any residual SO₂ and/or sulfur vapor is hydrogenated and thereby converted to hydrogen sulfide. In one aspect, the hydrogen source may be a refinery gas stream, although any useful hydrogen source may be employed.

In one embodiment, the hydrogenated fluid stream exits the hydrogenation reactor 28 at about 400-500° F. although other hydrogenation temperature profiles may be employed. In one embodiment, the fluid stream exiting the hydrogenation reactor 28 is directed to a cooler 30, wherein the fluid stream is cooled to about 300° F. In one aspect, the cooler 30 may be employed to produce steam, as would be understood by one skilled in the art. In one embodiment, the fluid stream exiting the cooler 30 is flowed directly to a contacter 32, although the invention is not so limited, and in other embodiments (not shown) additional equipment may be employed between the cooler 30 and the contacter 32 to further cool the fluid stream.

In one embodiment (not shown), when a quench tank is employed, a water source (not shown) may be utilized to introduce water into the quench tank. In one aspect, water within the quench tank serves to ensure that substantially all SO₂ is removed from the vapor therewithin. In one embodiment, (also not shown) a small amount of caustic (NaOH) may be introduced into the quench tank to control the pH of the liquid therewithin. In one embodiment, a fluid stream 38 comprising an amine, such as, but not limited to, diethylamine (DEA), is introduced into the contacter 32. In one embodiment, the amine-containing fluid stream 38 may originate in an industrial amine unit, although any source of amine may be employed. In one embodiment, the contacter 32 bottoms effluent 36 may be further manipulated, as would be understood by one skilled in the art. In one aspect, the liquid bottoms effluent 36 may be directed back to the same amine unit from which the fluid stream 38 originates. In one embodiment, an overhead gaseous stream 34 exits the contacter 32 which may be further manipulated, as would be understood by one skilled in the art. In one aspect, the overhead gaseous effluent 34 may be directed back to the same refinery fuel gas stream 42.

In other embodiments, a desulfurization system 100 comprising a back-end system 24A may be operated as described above therefor. In one embodiment, in an “absorption mode,” a cold bed absorber 48 is operated below the sulfur dew point, at about 250° F. to about 300° F. In one aspect, this greatly increases the Claus conversion which is favored by low temperature. Since the bed is operated below the sulfur dew point, sulfur is deposited in the converter bed which temporarily deactivates the catalyst. In a subsequent “regeneration mode,” a hot gas (in one embodiment, ˜600° F.) is introduced to the cold bed absorber 48 and the S₂ is vaporized. The thus vaporized S₂ flows as described above into cold bed absorber condenser 52 and is collected therefrom.

In one embodiment, fluid that is provided to a crystallizer 54 experiences a first cold mode (typically 200° F. to 230° F.) wherein sulfur vapor solidifies, and then a hot mode (typically about 275° F. to about 300° F.), whereby the solid S₂ liquifies and flows as described above into crystallizer condenser 58 and is collected therefrom. In one embodiment, gas exiting the crystallizer(s) 54 is routed to the quench tower 60 and processed as described above to remove residual SO₂ contained therein.

In various embodiments (not shown), partially and/or substantially desulfurized fluid streams may be obtained from any or all condensers within any or all desulfurization zones 22 of a desulfurization system 100. Similarly, back-end systems 24 and/or 24A may be employed with any or all desulfurization zones 22 of a desulfurization system 100.

Method

An exemplary method utilizing an embodiment of a desulfurization system of the present invention comprises:

A Desulfurization System Provision Step, comprising providing a desulfurization system, such as desulfurization system 100, comprising a mixing vessel, such as mixing vessel 2, and one or more desulfurization zones, such as desulfurization zones 22, each comprising, in sequence, a reheater, such as reheater 4, a reactor, such as reactor 6, and a condenser, such as condenser 8;

A Fluid Mixing Step, comprising mixing a hydrocarbon fluid stream, such as hydrocarbon input stream 42, with a sulfur dioxide stream, such as SO₂ input stream 44, in the mixing vessel;

A Desulfurization Step, comprising flowing the mixed stream output from the mixing vessel though at least one desulfurization zone; and

A Sulfur Removal Step, comprising removing sulfur at least one desulfurization zone condenser.

Optionally, one or more of the following steps may be performed:

• • A Hydrogenation Step; comprising flowing a fluid output stream, such as fluid output stream 40, into a hydrogenation reactor, such as hydrogenation reactor 28, wherein hydrogen is reacted therewith;
  • A Cold Bed Absorption Step, comprising flowing a fluid output stream, such as fluid output stream 40, into a cold be absorber, such as cold bed absorber 48, and first depositing S₂ therein and then flow liquified S₂ therefrom;
  • A Crystallization Step, comprising flowing a fluid output stream, such as fluid output stream 50, into a crystallizer, such as crystallizer 54, and first depositing S₂ therein and then flow liquified S₂ therefrom;
  • A Sulfur Dioxide Removal Step, comprising flowing the hydrogenated fluid stream exiting the hydrogenation reactor into a contacter, such as contacter 32, wherein the fluid stream is combined with water and/or an amine-containing fluid, such that SO₂ is substantially nonexistent in a gaseous overhead stream exiting the contacter.
  • A Sulfur Dioxide Removal Step, comprising flowing the stream exiting either a cold be absorber, such as cold bed absorber 48, or a crystallizer, such as crystallizer 54, into a circulating loop comprising a quench tower, such as quench tower 60, such that SO₂ is substantially nonexistent in a gaseous overhead stream exiting the quench tower.

The foregoing methods are merely exemplary, and additional embodiments of utilizing a floating oil absorption apparatus of the present invention consistent with the teachings herein may be employed. In addition, in other embodiments, one or more of these steps may be performed concurrently, combined, repeated, re-ordered, or deleted, and/or additional steps may be added.

The foregoing description of the invention illustrates exemplary embodiments thereof. Various changes may be made in the details of the illustrated construction and process within the scope of the appended claims by one skilled in the art without departing from the teachings of the invention. The present invention should only be limited by the claims and their equivalents.