Method for syngas clean-up of semi-volatile organic compounds with carbonyl sulfide removal

• US 10,011,483 B2
• Filed: 02/13/2017
• Issued: 07/03/2018
• Est. Priority Date: 09/27/2011
• Status: Active Grant

• Current Assignee: Thermochem Recovery International, Inc.
• Original Assignee: Thermochem Recovery International, Inc.
• Inventors: Chandran, Ravi, Leo, Daniel Michael, Freitas, Shawn Robert, Newport, Dave G., Whitney, Hamilton Sean Michael, Burciaga, Daniel A.
• Primary Examiner(s): Wartalowicz, Paul A
• Application Number:
  US15/430,654
• Publication Number:
  US 20170152140A1
• Time in Patent Office: 505 Days
• CPC Class Codes: B01D 17/0208 by sedimentation
• CPC Class Codes: B01D 2252/102 Ammonia
• CPC Class Codes: B01D 2252/103 Water
• CPC Class Codes: B01D 2252/20436 Cyclic amines
• CPC Class Codes: B01D 2252/504 Mixtures of two or more absorbents
• CPC Class Codes: B01D 2252/602 Activators, promoting agents, catalytic agents or enzymes
• CPC Class Codes: B01D 2256/16 Hydrogen
• CPC Class Codes: B01D 2256/20 Carbon monoxide
• CPC Class Codes: B01D 2257/304 Hydrogen sulfide
• CPC Class Codes: B01D 2257/306 Organic sulfur compounds, e.g. mercaptans
• CPC Class Codes: B01D 2257/406 Ammonia
• CPC Class Codes: B01D 2257/504 Carbon dioxide
• CPC Class Codes: B01D 2257/60 Heavy metals or heavy metal compounds
• CPC Class Codes: B01D 2257/708 Volatile organic compounds V.O.C.'s
• CPC Class Codes: B01D 2259/402 using two beds
• CPC Class Codes: B01D 29/27 Filter bags
• CPC Class Codes: B01D 29/66 by flushing, e.g. counter-current air-bumps
• CPC Class Codes: B01D 46/0036 by adsorption or absorption
• CPC Class Codes: B01D 47/10 Venturi scrubbers
• CPC Class Codes: B01D 5/0027 by direct contact between vapours or gases and the cooling medium
• CPC Class Codes: B01D 5/006 : with evaporation or distillation
• CPC Class Codes: B01D 5/0072 : with filtration
• CPC Class Codes: B01D 5/0075 : with heat exchanging B01D5/0039 takes precedence
• CPC Class Codes: B01D 5/009 : Collecting, removing and/or treatment of the condensate
• CPC Class Codes: B01D 50/60 : Combinations of devices covered by groups B01D46/00 and B01D47/00
• CPC Class Codes: B01D 53/0423 : Beds in columns
• CPC Class Codes: B01D 53/0462 : Temperature swing adsorption
• CPC Class Codes: B01D 53/047 : Pressure swing adsorption
• CPC Class Codes: B01D 53/0476 : Vacuum pressure swing adsorption
• CPC Class Codes: B01D 53/12 : according to the "fluidised technique"
• CPC Class Codes: B01D 53/1406 : Multiple stage absorption
• CPC Class Codes: B01D 53/1412 : Controlling the absorption process
• CPC Class Codes: B01D 53/1431 : Pretreatment by other processes
• CPC Class Codes: B01D 53/1462 : Removing mixtures of hydrogen sulfide and carbon dioxide
• CPC Class Codes: B01D 53/1468 : Removing hydrogen sulfide
• CPC Class Codes: B01D 53/1487 : Removing organic compounds
• CPC Class Codes: B01D 53/18 : Absorbing units; Liquid distributors therefor B01D3/16, B01D3/26, B01D3/30 take precedence; packing elements B01J19/30, B01J19/32
• CPC Class Codes: B01D 53/265 : by refrigeration (condensation)
• CPC Class Codes: B01D 53/326 : in electrochemical cells
• CPC Class Codes: B01D 53/48 : Sulfur compounds
• CPC Class Codes: B01D 53/76 : Gas phase processes, e.g. by using aerosols
• CPC Class Codes: B01D 61/362 : Pervaporation
• CPC Class Codes: B01D 61/3621 : comprising multiple pervaporation steps
• CPC Class Codes: C01B 2203/0227 : containing a catalytic reforming step
• CPC Class Codes: C01B 2203/0233 : the reforming step being a steam reforming step
• CPC Class Codes: C01B 2203/025 : containing a partial oxidation step
• CPC Class Codes: C01B 2203/0261 : containing a catalytic partial oxidation step [CPO]
• CPC Class Codes: C01B 2203/04 : containing a purification step for the hydrogen or the synthesis gas
• CPC Class Codes: C01B 2203/0415 : Purification by absorption in liquids
• CPC Class Codes: C01B 2203/042 : Purification by adsorption on solids
• CPC Class Codes: C01B 2203/043 : Regenerative adsorption process in two or more beds, one for adsorption, the other for regeneration
• CPC Class Codes: C01B 2203/0435 : Catalytic purification
• CPC Class Codes: C01B 2203/045 : Purification by catalytic desulfurisation
• CPC Class Codes: C01B 2203/0465 : Composition of the impurity
• CPC Class Codes: C01B 2203/0475 : the impurity being carbon dioxide
• CPC Class Codes: C01B 2203/048 : the impurity being an organic compound
• CPC Class Codes: C01B 2203/0485 : the impurity being a sulfur compound
• CPC Class Codes: C01B 2203/061 : Methanol production
• CPC Class Codes: C01B 2203/062 : Hydrocarbon production, e.g. Fischer-Tropsch process
• CPC Class Codes: C01B 2203/068 : Ammonia synthesis
• CPC Class Codes: C01B 2203/0877 : by direct injection of fluid
• CPC Class Codes: C01B 2203/1235 : Hydrocarbons
• CPC Class Codes: C01B 2203/1241 : Natural gas or methane
• CPC Class Codes: C01B 2203/142 : At least two reforming, decomposition or partial oxidation steps in series
• CPC Class Codes: C01B 2203/147 : Three or more purification steps in series
• CPC Class Codes: C01B 2203/84 : Energy production
• CPC Class Codes: C01B 3/24 : of hydrocarbons
• CPC Class Codes: C01B 3/38 : using catalysts
• CPC Class Codes: C01B 3/382 : Multi-step processes
• CPC Class Codes: C01B 3/386 : Catalytic partial combustion
• CPC Class Codes: C01B 3/52 : by contacting with liquids; Regeneration of used liquids C01B3/508 takes precedence
• CPC Class Codes: C01B 3/56 : by contacting with solids; Regeneration of used solids C01B3/508 takes precedence
• CPC Class Codes: C01B 3/58 : including a catalytic reaction
• CPC Class Codes: H05K 999/99 : dummy group
• CPC Class Codes: Y02C 20/40 : of CO2
• CPC Class Codes: Y02P 20/129 : Energy recovery, e.g. by cogeneration, H2recovery or pressure recovery turbines
• CPC Class Codes: Y02P 30/00 : Technologies relating to oil refining and petrochemical industry

Abstract

A system and method for processing unconditioned syngas first removes solids and semi-volatile organic compounds (SVOC), then removes volatile organic compounds (VOC), and then removes at least one sulfur containing compound from the syngas. Additional processing may be performed depending on such factors as the source of syngas being processed, the products, byproducts and intermediate products desired to be formed, captured or recycled and environmental considerations.

Claims

1. A method for cleaning unconditioned syngas for introduction into a syngas processing technology application, the unconditioned syngas including semi-volatile organic compounds (SVOC), at least one or both of hydrogen chloride and hydrogen sulfide, and having a carbonyl sulfide concentration greater than 0 ppm and less than or equal to 15 ppm, the method comprising:

(a) contacting the unconditioned syngas with water to reduce the temperature of the syngas to below the SVOC condensation temperature to thereby form an intermediate SVOC-depleted syngas containing steam, and a first mixture comprising SVOC, solids and water;

(b) removing steam from the intermediate SVOC-depleted syngas containing steam to form (i) a first depleted syngas stream which has a reduced amount of SVOC and solids relative to the unconditioned gas, and (ii) a second mixture comprising SVOC, solids and water;

(c) after step (b), removing hydrogen chloride and/or hydrogen sulfide from the first depleted syngas stream with a scrubber;

(d) after step (c), compressing the syngas to a pressure ranging from 100 PSIG to 2,000 PSIG;

(e) after step (d), removing at least a portion of the carbonyl sulfide from the syngas;

(f) after step (e), removing carbon dioxide from the syngas with one or more from the group consisting of a membrane, an adsorber and an absorber;

wherein;

(i) the carbonyl sulfide concentration after step (e) is less than or equal to 30 ppb;

(ii) the hydrogen chloride concentration in unconditioned syngas ranges from greater than 0 ppm to less than or equal to 1000 ppm;

(iii) the hydrogen chloride capture efficiency of the scrubber is greater than 80%;

(iv) the hydrogen sulfide concentration ranges from greater than 0 ppm to less than or equal to 1000 ppm;

(v) the hydrogen sulfide capture efficiency of the scrubber is greater than 80%;

(vi) the carbon dioxide concentration to step (f) ranges from 10% by volume to 40% by volume; and

(vii) the carbon dioxide capture efficiency of step (f) is greater than 20%.

2. The method of claim 1, comprising, in step (e):

In step (e) injecting water into a packed hydrolysis bed containing alumina media, to hydrolyze the carbonyl sulfide.

3. The method of claim 2, comprising:

converting the carbonyl sulfide into carbon dioxide and hydrogen sulfide.

4. The method of claim 1, wherein:

the unconditioned syngas has a metal concentration greater than 0 ppm and less than or equal to 30 ppm, said metal being one or more from the group consisting of mercury, arsenic, lead, and cadmium; and

the method further comprises;

after step (d) and before step (e), removing at least a portion of said metal such that the metal concentration is less than or equal to 10 ppb.

5. The method of claim 4, comprising:

removing said metal with a cylindrical pressure vessel containing one or more from the group consisting of cellulose acetate, cellulose acetate packing, cellulose acetate beads, cellulose acetate spheres, cellulose acetate flake, cellulose acetate pellets, and sorbents.

6. The method of claim 1, comprising, in step (d):

compressing syngas with a syngas compressor from a first pressure ranging from 15 PSIG to 50 PSIG to a second higher pressure ranging from 100 PSIG to 2,000 PSIG.

7. The method of claim 6, comprising:

introducing a gaseous hydrocarbon source to the inlet of the syngas compressor, said gaseous hydrocarbon including one or more from the group consisting of natural gas, syngas, refinery offgases, naphtha, methanol, ethanol, petroleum, methane, ethane, propane, butane, hexane, benzene, toluene, xylene, and naphthalene.

8. The method of claim 1, wherein:

the unconditioned syngas has an ammonia concentration greater than 0 ppm and less than or equal to 1000 ppm; and

the method further comprises;

after step (d) and before step (e), removing at least a portion of the ammonia with a capture efficiency greater than 80%.

9. The method of claim 8, comprising removing ammonia with water in a scrubber.

10. The method of claim 9, wherein:

after removing ammonia with water in a scrubber, the syngas has a residual ammonia concentration greater than 0 ppm and less than or equal to 15 ppm; and

the method further comprises;

polishing ammonia in a fixed bed adsorber such that the ammonia concentration is reduced to less than or equal to 10 ppb.

11. The method of claim 10, wherein:

the fixed bed adsorber comprises a cylindrical pressure vessel containing one or more from the group consisting of sorbents, molecular sieve type 4A, 5A sorbents, 13×

sorbents, dealuminated faujasite, dealuminated pentasil, and clinoptilolite.

12. The method of claim 1, comprising:

(g) after step (f), removing sulfur with a fixed bed adsorber to reduce sulfur concentration to less than 30 ppb.

13. The method of claim 12, comprising:

removing at least one sulfur containing compound with a cylindrical pressure vessel containing one or more from the group consisting of sorbent media, zinc oxide sorbent media, zinc oxide beads, zinc oxide pellets, zinc oxide granules, zinc oxide spheres, and zinc oxide packing.

14. The method of claim 1, comprising:

(g) after step (f), steam methane reforming to form hydrogen and carbon monoxide within a steam methane reformer.

15. The method of claim 14, wherein:

the steam methane reformer accepts an inlet gaseous hydrocarbon concentration ranges from 1 wt % to 100 wt %; and

the steam methane reformer operates at a conversion efficiency ranging from 50% to 100%.

16. The method of claim 14, wherein:

the steam methane reformer accepts an inlet SVOC concentration greater than 0 ppm; and

the steam methane reformer operates at a conversion efficiency greater than 50%.

17. The method of claim 14, wherein:

the steam methane reformer accepts an inlet volatile organic compound (VOC) concentration greater than 0 ppm; and

the steam methane reformer operates at a conversion efficiency greater than 50%.

18. The method of claim 1, comprising:

in step (c), introducing the first depleted syngas stream into a scrubber; and

removing hydrogen chloride from the first depleted syngas stream, using water as the main scrubbing absorption liquid in said scrubber.

19. The method of claim 18, comprising:

condensing residual steam contained within the syngas to provide at least a portion of said water as the main scrubbing absorption liquid.

20. The method of claim 18, wherein:

the scrubber comprises a pressure vessel having a lower section, an upper section, and a central section located between the upper and lower sections, the central section containing packing; and

the method comprises;

introducing water into the packing of the central section; and

introducing the first depleted syngas stream into the lower section of the scrubber so that the first depleted syngas stream passes up through the central section and comes into intimate contact with the water traveling countercurrently via gravity flow down through the packing.

21. The method of claim 20, wherein:

the scrubber is connected to a recirculation pump via recirculation piping; and

the method further comprises;

removing water from the scrubber by a level control loop including a level transmitter and a level control valve; and

operating said level transmitter and said level control valve such that water is bled from the recirculation piping, via a waste transfer conduit, to maintain a steady liquid level within the lower section of the scrubber.

22. The method of claim 21, comprising:

receiving water into the recirculation pump from the lower section of the scrubber; and

transferring the water from the recirculation pump through a heat exchanger, prior to introducing the water back into the upper section of the scrubber, from which upper section the water travels downwards onto the scrubber central packing.

23. The method of claim 22, wherein:

the heat exchanger is of the shell and tube type, with a cooling water supply and a cooling water return communicating with the shell-side of the heat exchanger; and

the method further comprises;

indirectly removing heat from the water received from the recirculation pump, prior to introducing the water back into the upper section of the scrubber.

24. The method of claim 23, comprising:

introducing water into the packing of the central section via a spray nozzle system comprising one more spray nozzles or spray balls.

25. The method of claim 24, wherein:

the upper section includes a demister positioned above the spray nozzle system; and

the method further comprises;

removing, with the demister, liquid droplets from the upper section to minimize carry-over losses of the water.

26. The method of claim 25, wherein:

the scrubber is connected to a recirculation pump via recirculation piping; and

the method further comprises;

removing water from the scrubber by a level control loop including a level transmitter and a level control valve; and

operating said level transmitter and said level control valve such that water is bled from the recirculation piping, via a waste transfer conduit, to maintain a steady liquid level within the lower section of the scrubber.

27. The method of claim 1, comprising:

in step (c), introducing the first depleted syngas stream into a scrubber; and

removing hydrogen sulfide from the first depleted syngas stream, using a hydrogen sulfide scavenger as the main scrubbing absorption liquid in said scrubber.

28. The method of claim 27, wherein:

the scrubber comprises a pressure vessel having a lower section, an upper section, and a central section located between the upper and lower sections, the central section containing packing; and

the method comprises;

introducing the scrubbing absorption liquid into the packing of the central section; and

introducing the first depleted syngas stream into the lower section of the scrubber so that the first depleted syngas stream passes up through the central section and comes into intimate contact with the scrubbing absorption liquid traveling countercurrently via gravity flow down through the packing.

29. The method of claim 28, wherein:

the scrubber is connected to a recirculation pump via recirculation piping; and

the method further comprises;

removing hydrogen sulfide scavenger from the scrubber by a level control loop including a level transmitter and a level control valve; and

operating said level transmitter and said level control valve such that hydrogen sulfide scavenger is bled from the recirculation piping, via a waste transfer conduit, to maintain a steady liquid level within the lower section of the scrubber.

30. The method of claim 28, comprising:

introducing the hydrogen sulfide scavenger into the packing of the central section via a spray nozzle system comprising one more spray nozzles or spray balls.

31. The method of claim 30, wherein:

the upper section includes a demister positioned above the spray nozzle system; and

the method further comprises;

removing, with the demister, liquid droplets from the upper section to minimize carry-over losses of the hydrogen sulfide scavenger.

32. The method of claim 31, wherein:

the scrubber is connected to a recirculation pump via recirculation piping; and

the method further comprises;

removing hydrogen sulfide scavenger from the scrubber by a level control loop including a level transmitter and a level control valve; and

operating said level transmitter and said level control valve such that hydrogen sulfide scavenger is bled from the recirculation piping, via a waste transfer conduit, to maintain a steady liquid level within the lower section of the scrubber.

33. The method of claim 27, wherein the hydrogen sulfide scavenger is a triazine solution.

34. The method of claim 33, wherein the triazine solution comprises triazine diluted with water to between 0.01 wt % and 1 wt % triazine.

35. The method according to claim 1, further comprising:

prior to step (a), hydrocarbon reforming at least a portion of the unconditioned syngas to increase an amount of hydrogen (H2) and carbon monoxide (CO) in the unconditioned syngas.

36. The method according to claim 35, comprising hydrocarbon reforming with at least one or more from the group consisting of non-thermal, non-catalytic, and cold plasma gliding-arc.

37. The method according to claim 35, comprising hydrocarbon reforming by partial oxidation.

38. The method according to claim 35, comprising hydrocarbon reforming by using a catalyst.

39. The method according to claim 35, comprising:

mixing a gaseous hydrocarbon with the unconditioned syngas, the gaseous hydrocarbon being one or more from the group consisting of natural gas, syngas, refinery offgases, methanol, ethanol, petroleum, methane, ethane, propane, butane, hexane, benzene, toluene, xylene, wax, low melting solids, paraffin wax, and naphthalene;

mixing an oxidant with the unconditioned syngas, the oxidant being one or more from the group consisting of carbon dioxide, steam, air, and oxygen; and

reacting the unconditioned syngas with said gaseous hydrocarbon and said oxidant in a hydrocarbon reformer to generate H2 and CO;

wherein;

said gaseous hydrocarbons are converted into H2 and CO at a conversion efficiency between 50% and 100%.

40. The method according to claim 39, wherein:

the SVOC concentration in the unconditioned syngas is between 10 ppm and 1,000 ppm, and the method comprises;

hydrocarbon reforming SVOC in the unconditioned syngas to produce H2 and CO, at a conversion efficiency greater than 50%.

41. The method according to claim 39, wherein:

the unconditioned syngas includes volatile organic compounds (VOC) at concentration between 500 ppm and 10,000 ppm, and the method comprises;

hydrocarbon reforming VOC in the unconditioned syngas to produce H2 and CO, at a conversion efficiency greater than 50%.

42. The method according to claim 35, comprising:

after hydrocarbon reforming and still prior to step (a), cooling the unconditioned syngas to between 250°

F. and 650°

F.

43. The method according to claim 35, comprising:

after hydrocarbon reforming and still prior to step (a), cooling the unconditioned syngas in a shell and tube heat exchanger, wherein the unconditioned syngas travels through the tube-side and indirectly contacts steam located on the shell-side.

44. The method according to claim 35, comprising:

after hydrocarbon reforming and still prior to step (a);

cooling the unconditioned syngas and generating superheated steam by using a heat recovery steam generator superheater (HRSG superheater) configured to receive steam from a steam drum;

further cooling the unconditioned syngas and generating steam using a heat recovery steam generator (HRSG) configured to receive water from the steam drum; and

transferring the steam generated by the HRSG back to the steam drum.

45. The method according to claim 44, wherein:

the steam drum is operated under both pressure control with a pressure transmitter and level control with a level transmitter;

the pressure transmitter acts in communication with a pressure control valve which opens and releases pressure on automatic pressure control, to maintain a pressure in the steam drum;

the level transmitter acts in communication with a level control valve located on a water supply line to provide water to maintain sufficient level in the steam drum to allow recirculation of water through the HRSG; and

a purge of water flows from the steam drum through a steam drum continuous blowdown line to regulate a concentration of suspended and total dissolved solids within a volume of water contained within the steam drum.

46. The method according to claim 35, comprising:

after hydrocarbon reforming and still prior to step (a), generating superheated steam from steam, by cooling at least a portion of the H2 and CO generated by said hydrocarbon reforming.

47. The method according to claim 46, comprising:

after hydrocarbon reforming and still prior to step (a), generating steam by further cooling said at least a portion of the H2 and CO generated by said hydrocarbon reforming.

48. The method according to claim 1, comprising:

prior to step (a), cooling the unconditioned syngas and generating steam by use of a heat recovery steam generator (HRSG) connected to a steam drum, and returning the generated steam to the steam drum;

wherein;

the steam drum is operated under both pressure control with a pressure transmitter and level control with a level transmitter;

the pressure transmitter acts in communication with a pressure control valve which opens and releases pressure on automatic pressure control, to maintain a pressure in the steam drum; and

the level transmitter acts in communication with a level control valve located on a water supply line to provide water to maintain sufficient level in the steam drum to allow recirculation of water through the HRSG;

a purge of water flows from the steam drum through a steam drum continuous blowdown line to regulate a concentration of suspended and total dissolved solids within a volume of water contained within the steam drum.

49. The method according to claim 48, comprising:

transferring steam from the steam drum to an HRSG superheater via a saturated steam transfer line, so that the steam indirectly contacts unconditioned syngas flowing through the HRSG superheater and becomes superheated steam.

50. The method according to claim 48, comprising:

generating superheated steam by cooling at least a portion of the unconditioned syngas.

51. The method according to claim 50, comprising:

generating steam by further cooling said at least a portion of the unconditioned syngas.

52. The method according to claim 1, comprising:

prior to step (a);

cooling the unconditioned syngas and generating superheated steam by use of a heat recovery steam generator superheater (HRSG superheater) configured to receive steam from a steam drum;

further cooling the unconditioned syngas and generating steam by use of a heat recovery steam generator (HRSG) configured to receive water from the steam drum; and

transferring the steam generated by the use of the HRSG to the steam drum.

53. The method according to claim 52, wherein:

the steam drum is operated under both pressure control with a pressure transmitter and level control with a level transmitter;

the pressure transmitter acts in communication with a pressure control valve which opens and releases pressure on automatic pressure control, to maintain a pressure in the steam drum;

the level transmitter acts in communication with a level control valve located on a water supply line to provide water to maintain sufficient level in the steam drum to allow recirculation of water through the HRSG; and

a purge of water flows from the steam drum through a steam drum continuous blowdown line to regulate a concentration of suspended and total dissolved solids within a volume of water contained within the steam drum.

54. The method according to claim 1, wherein:

the unconditioned syngas includes volatile organic compounds (VOC); and

the method further comprises;

after step (d) and before step (e), removing at least a portion of the VOC from the unconditioned syngas, by adsorption.

55. The method according to claim 54, comprising:

removing said at least a portion of the VOC via pressure swing adsorption.

56. The method according to claim 55, comprising:

desorbing VOC from an adsorbent via pressure swing desorption.

57. The method according to claim 54, comprising:

removing said at least a portion of the VOC via temperature swing adsorption.

58. The method according to claim 57, comprising:

desorbing VOC from an adsorbent via temperature swing desorption.

59. The method according to claim 54, comprising:

removing said at least a portion of the VOC via vacuum pressure swing adsorption.

60. The method according to claim 59, comprising:

desorbing VOC from an adsorbent by applying a vacuum.

61. The method according to claim 54, comprising:

adsorbing VOC from syngas with one or more from the group consisting of styrene based polymeric adsorbents, molecular sieves, zeolites, catalyst materials, silica gel, alumina, and activated carbon materials.

62. The method according to claim 61, comprising:

adsorbing said at least a portion of the VOC by use of a fixed bed.

63. The method according to claim 61, comprising:

adsorbing said at least a portion of the VOC by use of a fluidized bed.

64. The method of claim 1, comprising, in step (e):

removing carbonyl sulfide with a cylindrical pressure vessel containing one or more from the group consisting of packed bed media, packed alumina bed media, packed titania bed media, alumina, titania, alumina beads, alumina pellets, alumina granules, alumina spheres, alumina packing, titania beads, titania pellets, titania granules, titania spheres, and titania packing.

65. The method of claim 1, wherein:

the unconditioned syngas has a solid particulate concentration greater than 0 wt % and less than or equal to 0.1 wt %; and

the method further comprises;

after step (c) and before step (d), filtering out solid particulates with a capture efficiency between 99% and 100%.

66. The method of claim 1, wherein:

the unconditioned syngas has a volatile organic compound (VOC) concentration from 1 ppm to 500 ppm; and

the method further comprises;

after step (d) and before step (e), removing VOCs with a capture efficiency greater than 95%.

67. The method of claim 1, comprising:

(g) after step (f), exposing syngas to a carbon dioxide electrolyzer to convert carbon dioxide into carbon monoxide,

wherein;

the inlet carbon dioxide concentration ranges from 15 wt % to 45 wt %; and

the carbon dioxide electrolyzer operates conversion efficiency ranging from 50% to 100%.

68. The method according to claim 1, comprising:

(g) after step (f), introducing the syngas to a syngas processing technology application comprised of an industrial processing system that produces or synthesizes one or more from the group consisting of hydrogen, ethanol, mixed alcohols, methanol, dimethyl ether, chemicals, chemical intermediates, plastics, solvents, adhesives, fatty acids, acetic acid, olefins, oxochemicals, ammonia, Fischer-Tropsch products, naphtha, kerosene, diesel, lubricants, waxes, synthetic natural gas, power, heat, and electricity.

69. The method of claim 1, comprising:

in step (c), removing hydrogen sulfide from the first depleted syngas stream, using one or more from the group consisting of water, and a regenerable hydrogen sulfide scavenger.

70. The method of claim 1, comprising:

in step (c) removing hydrogen sulfide using one or more from the group consisting of UC Sulfur Recovery Process (UCSRP), solvent-based scrubbing systems using amines, solvent-based scrubbing systems using physical solvents, refrigerated solvent-based scrubbing systems using amines, refrigerated solvent-based scrubbing systems using physical solvents, Rectisol, Selexol, Sulfinol, sorbents, glycol ether, diethylene glycol methyl ether (DGM), regenerable sorbents, non-regenerable sorbents, molecular sieve zeolites, calcium based sorbents, FeO-based sorbents, MgO-based sorbents, ZnO-based sorbents, FeO-based catalysts, MgO-based catalysts, ZnO-based catalysts, iron sponge, potassium-hydroxide-impregnated activated-carbon systems, alumina, impregnated activated alumina, titanium dioxide catalysts, vanadium pentoxide catalysts, tungsten trioxide catalysts, sulfur bacteria, thiobacilli, sodium biphospahte solutions, aqueous ferric iron chelate solutions, potassium carbonate solutions, alkali earth metal chlorides, magnesium chloride, barium chloride, crystallization techniques, bio-catalyzed scrubbing processes, THIOPAQ scrubber, hydrodesulphurization catalysts, wet limestone scrubbing systems, spray dry scrubbers, Claus processing system, and solvent-based sulfur removal processes.

71. The method according to claim 1 wherein the unconditioned syngas comprises:

(a) carbon monoxide from 5 to 35 vol % dry;

(b) hydrogen from 20 to 60 vol % dry; and

,

(c) methane from 1 to 15 vol % dry.

72. The method according to claim 1, wherein the unconditioned syngas includes one or more from the group consisting of ethylene ranging from 0 to 4 vol % dry, ethane ranging from 0 to 2 vol % dry, acetylene ranging from 0 to 1 vol % dry, ammonia ranging from 0 to 1,000 ppmV dry, hydrogen chloride ranging from 0 to 1,000 ppmV dry, hydrogen cyanide ranging from 0 to 50 ppmV dry, and hydrogen sulfide ranging from 0 to 1,000 ppmV dry.

73. The method according to claim 1 wherein the unconditioned syngas includes volatile organic compounds (VOC) comprising one or more from the group consisting of aromatics, benzene, toluene, phenol, styrene, xylene, and cresol.

74. The method according to claim 1 wherein the semi-volatile organic compounds (SVOC) comprise one or more from the group consisting of polyaromatics, indene, indan, napthalene, methylnapthalene, acenapthylene, acenapthalene, anthracene, phenanthrene, (methyl-) anthracenes/phenanthrenes, pyrene/fluoranthene, methylpyrenes/benzofluorenes, chrysene, benz[a]anthracene, methylchrysenes, methylbenz[a]anthracenes, perylene, benzo[a]pyrene, dibenz[a,kl]anthracene, and dibenz[a,h]anthracene.

75. The method according to claim 1, wherein:

the unconditioned syngas comprises undesirable syngas constituents including hydrocarbons, SVOCs and volatile organic compounds (VOCs), the VOCs having a concentration between 500 ppm and 10,000 ppm in the unconditioned syngas, and the method comprises;

prior to step (a) converting a portion of the undesirable syngas constituents in the unconditioned syngas into hydrogen (H2) and carbon monoxide (CO) by;

(a1) mixing the unconditioned syngas with an oxidant and a gaseous hydrocarbon;

(a2) generating H2 and CO from the mixture of unconditioned syngas, oxidant and the gaseous hydrocarbon, with VOC in the mixture being converted into H2 and CO at a conversion efficiency greater than 50%, and gaseous hydrocarbon in the mixture being converted into H2 and CO at a conversion efficiency of 50 to 100%; and

(a3) generating steam by cooling at least a portion of the H2 and CO generated in step (a2) to between 250°

F. and 650°

F., using a heat recovery steam generator (HRSG);

wherein;

said gaseous hydrocarbon is one or more from the group consisting of natural gas, syngas, refinery offgases, methanol, ethanol, petroleum, methane, ethane, propane, butane, hexane, benzene, toluene, xylene, wax, low melting solids, paraffin wax and naphthalene;

said oxidant is one or more from the group consisting of carbon dioxide, steam, air, and oxygen;

the HRSG is integrated with a steam drum operated under both pressure control with a pressure transmitter and level control with a level transmitter;

the pressure transmitter acts in communication with a pressure control valve which opens and releases pressure on automatic pressure control, to maintain a pressure in the steam drum; and

the level transmitter acts in communication with a level control valve located on a water supply line to provide water to maintain sufficient level in the steam drum to allow recirculation of water through the HRSG;

saturated steam is transferred from the steam drum to an HRSG superheater via a saturated steam transfer line; and

a purge of water flows from the steam drum through a steam drum continuous blowdown line to regulate a concentration of suspended and total dissolved solids within a volume of water contained within the steam drum.