METHODS AND APPARATUS FOR SULFUR
RECOVERY FROM ACID GASES
BACKGROUND
1. Technical Field
[0001] One or more embodiments of the invention relate to methods and apparatus for
recovering sulfur from an acid gas.
2. Description of Related Art
[0002] A variety of industrial processes, such as natural gas processing, oil refining, and coal
gasification, can produce acid gases that contain carbon dioxide and hydrogen sulfide, as well as
other sulfur compounds, such as carbonyl sulfide and/or mcrcaptans. Such acid gases may be
treated to recover valuable sulfur contained therein and to reduce sulfur emissions to the
atmosphere. For instance, an acid gas can undergo an enrichment process where the hydrogen
sulfide in the acid gas is concentrated and then treated in a Claus sulfur recovery unit. Claus
sulfur recovery processes treat such enriched streams to convert hydrogen sulfide into
recoverable sulfur while producing an off-gas that is suitable for incineration before venting to
the atmosphere. While advances have been made in the art of sulfur recovery from acid gases,
improvements are still needed, particularly for lean acid gases.
SUMMARY
[0003] One embodiment of the invention concerns a process for recovering sulfur from an
acid gas comprising hydrogen sulfide. The method of this embodiment comprises contacting the
acid gas with a partially-loaded sulfur absorbing solvent in an acid gas enrichment zone to
thereby produce a hydrogen sulfide rich sulfur absorbing solvent and a hydrogen sulfide depleted
off-gas, where the hydrogen sulfide depleted off-gas comprises hydrogen sulfide in an amount of
at least 0.5 mole percent, and where, prior to contacting, the partially-loaded sulfur absorbing
solvent comprises hydrogen sulfide in an amount of at least 0.01 mole percent.
[0004] Another embodiment of the invention concerns a process for recovering sulfur from
an acid gas comprising hydrogen sulfide. The process of this embodiment comprises: (a)
contacting the acid gas in an acid gas enrichment zone with a partially-loaded sulfur absorbing
solvent to thereby produce a hydrogen sulfide rich sulfur absorbing solvent and a hydrogen
sulfide depleted off-gas; (b) removing at least a portion of the hydrogen sulfide from the
hydrogen sulfide rich sulfur absorbing solvent to thereby produce an enriched hydrogen sulfide
stream and a regenerated sulfur absorbing solvent; and (c) contacting at least a portion of the
regenerated sulfur absorbing solvent with a hydrogenated stream containing hydrogen sulfide to
thereby produce the partially-loaded sulfur absorbing solvent, wherein the hydrogen sulfide
content of the hydrogen sulfide rich sulfur absorbing solvent is at least 2,6 mole percent.
[0005] Yet another embodiment of the invention concerns a sulfur recovery system for
recovering sulfur from an acid gas. The sulfur recovery system of this embodiment comprises:
an acid gas enrichment absorber vessel containing a sulfur absorbing solvent operable for
removing hydrogen sulfide from the acid gas; a sulfur absorbing solvent regenerator in
downstream fluid communication with the acid gas enrichment absorber vessel and operable for
separating hydrogen sulfide from the sulfur absorbing solvent and generating an enriched
hydrogen sulfide stream and a regenerated sulfur absorbing solvent; a Claus sulfur recovery unit
in downstream fluid communication with the sulfur absorbent regenerator and operable for
recovering sulfur from the enriched hydrogen sulfide stream; a heater/mixer unit in downstream
fluid communication with the Claus sulfur recovery unit and the acid gas enrichment vessel and
operable for mixing and heating a tail gas from the Claus sulfur recovery unit and a hydrogen
sulfide depleted off-gas from the acid gas enrichment absorber vessel; a hydrogenation unit in
downstream fluid communication with the heater/mixer unit operable for hydrogenating a
hydrogenation feed stream discharged from the heater/mixer unit; a quench column in
downstream fluid communication with the hydrogenation unit; and a tail gas treatment absorber
vessel in downstream fluid communication with the quench column and operable for removing
hydrogen sulfide from a hydrogenated Claus tail gas and acid gas enrichment off-gas.
BRIEF DESCRIPTION OF THE DRAWING FIGURES
[0006] Embodiments of the present invention are described herein with reference to the
attached drawing figures, wherein:
[0007] FIG. 1 is a process flow diagram illustrating a system for sulfur recovery from an acid
gas constructed in accordance with certain embodiments of the present invention, particularly
illustrating a configuration where an initial acid gas is contacted in an acid gas enrichment zone
with a partially-loaded sulfur absorbing solvent from a tail-gas treatment zone, and where a
hydrogen sulfide depleted off-gas from the acid gas enrichment zone is combined with a tail gas
from a sulfur recovery zone for treatment in a hydrogenation zone; and
[0008] FIG. 2 is a process flow diagram illustrating in detail a sulfur recovery unit
constructed in accordance with certain embodiments of the present invention.
DETAILED DESCRIPTION
[0009] The following detailed description of the invention references the accompanying
drawings that illustrate specific embodiments in which the invention can be practiced. The
embodiments are intended to describe aspects of the invention in sufficient detail to enable those
skilled in the art to practice the invention. Other embodiments can be utilized and changes can
be made without departing from the scope of the present invention. The following detailed
description is, therefore, not to be taken in a limiting sense. The scope of the present invention is
defined only by the appended claims, along with the full scope of equivalents to which such
claims are entitled.
[0010] Referring initially to FIG. 1, a sulfur removal system is depicted according to an
embodiment of the present invention. In the embodiment of FIG. 1, an acid gas can initially be
introduced into an acid gas enrichment zone 10 via line 12. As used herein, the term "acid gas"
shall denote a substantially vapor-phase stream containing at least 5 mole percent carbon dioxide
and at least 1 mole percent hydrogen sulfide. Acid gases can also contain additional
components, such as, for example, water; hydrocarbons, such as, for example, methane, ethane,
propane, butane, pentane, hexane, ethylene, and/or propylene; carbonyl sulfide ("COS"); and
mercaptans (a.k.a., thiols), such as, for example, methyl mercaptan (a.k.a., methanethiol) and
ethyl mercaptan (a.k.a., ethanethiol). Examples of acid gases suitable for use include, but are not
limited to, acid gases produced during oil refining processes, coal gasification processes, and
natural gas sweetening processes. In one or more embodiments, the acid gas in line 12 can
comprise an acid gas produced during a natural gas sweetening process.
[0011] As mentioned above, acid gases can contain hydrogen sulfide. In one or more
embodiments, the acid gas in line 12 can comprise hydrogen sulfide in a concentration of at least
1, at least 5, at least 10, at least 15, at least 20, or at least 25 mole percent. In other
embodiments, the acid gas in line 12 can comprise hydrogen sulfide in a concentration of less
than 50, less than 40, or less than 30 mole percent. Additionally, the acid gas in line 12 can
comprise hydrogen sulfide in an amount in the range of from about 1 to about 50 mole percent,
in the range of from about 10 to about 40 mole percent, or in the range of from 20 to 30 mole
percent.
[0012] As mentioned above, acid gases can contain carbon dioxide. In one or more
embodiments, the acid gas in line 2 can comprise carbon dioxide in a concentration of at least
30, at least 40, at least 50, or at least 60 mole percent. Additionally, the acid gas in line 1 can
comprise carbon dioxide in an amount in the range of from about 55 to about 85 mole percent, in
the range of from about 60 to about 80 mole percent, or in the range of from 65 to 75 mole
percent.
[0013] As mentioned above, acid gases can contain COS. In one or more embodiments, the
acid gas in line 12 can comprise COS in a concentration of at least 0.01, at least 0.02, at least
0.05, at least 0.1, at least 0.15, or at least 0.2 mole percent. Additionally, the acid gas in line 2
can comprise COS in an amount in the range of from about 0.001 to about 1 mole percent, in the
range of from about 0.01 to about 0.5 mole percent, or in the range of from 0.02 to 0.25 mole
percent.
[0014] As mentioned above, acid gases can contain mercaptans. In one or more
embodiments, the acid gas in line 12 can have a total mercaptan concentration of at least 0.01 , at
least 0.02, at least 0.05, at least 0.1, at least 0.15, or at least 0.2 mole percent. Additionally, the
acid gas in line 12 can have a total mercaptan concentration in an amount in the range of from
about 0.001 to about 1 mole percent, in the range of from about 0.01 to about 0.5 mole percent,
or in the range of from 0.02 to 0.25 mole percent. In one or more embodiments, the acid gas in
line 12 can have a combined concentration of methyl mercaptan and ethyl mercaptan of at least
0.01, at least 0.02, at least 0.05, at least 0.1, at least 0.15, or at least 0.2 mole percent. As used
herein, the term "combined concentration" when used to describe the concentration of two or
more components shall denote that any single component can constitute the full assessed
concentration, or any combination of the concentrations of two or more or all of the components
can be summed to constitute the full assessed concentration. Additionally, the acid gas in line
can have a combined concentration of methyl mercaptan and ethyl mercaptan in an amount in the
range of from about 0.001 to about 1 mole percent, in the range of from about 0.01 to about 0.5
mole percent, or in the range of from 0.02 to 0.25 mole percent.
[0015] As mentioned above, acid gases can contain COS and mercaptans. In one or more
embodiments, the acid gas in line 1 can have a combined concentration of COS and one or
more types of mercaptans of at least 0.01, at least 0.025, at least 0.05, at least 0.1, at least 0.15, or
at least 0.2 mole percent. Additionally, the acid gas in line 12 can have a combined
concentration of COS and one or more types of mercaptans in an amount in the range of from
about 0.01 to about 2 mole percent, in the range of from about 0.05 to about 1 mole percent, or in
the range of from 0.1 to 0.5 mole percent. Furthermore, the combined concentration of COS and
mercaptans in the acid gas in line 12 can constitute at least 0.1, at least 0.5, at least 1, or at least 2
mole percent of the total amount of sulfur compounds present in the acid gas in line 12 As used
herein, the term "sulfur compound" refers to any sulfur-containing molecule, including elemental
sulfur.
[0016] The acid gas in line 12 can be primarily in the vapor phase. As used herein the terms
"primarily," "predominately," and "majority" shall mean greater than 50 percent in one or more
embodiments, at least 80, at least 90, at least 95, or at least 99 mole percent of the acid gas in line
12 can be in the vapor phase. Additionally, in various embodiments, the acid gas in line 12 can
have temperature in the range of from about 10 to about 100 °C, in the range of from about 25 to
about 85 °C, or in the range of from 40 to 50 °C. Furthermore, the acid gas in line 12 can have a
pressure in the range of from about 0 to about 200 kilopascal gauge ("kPag"), in the range of
from about 50 to about 50 kPag, or in the range of from 75 to 125 kPag. Moreover, the acid gas
in line 12 can have a volume flow rate in the range of from about 100 to about 10,000 cubic
meters per hour ("m /hr"), in the range of from about 500 to about 5,000 m3/hr, or in the range of
from 1,000 to 3,000 m /hr.
[0017] As mentioned above, the acid gas in line 12 can be introduced into acid gas
enrichment zone 10. Acid gas enrichment zone 0 can operate to facilitate contact between the
acid gas introduced via line 12 and a partially-loaded sulfur absorbing solvent introduced into
acid gas enrichment zone 10 via line 14. Any methods or apparatus known or hereafter
discovered in the art suitable to facilitate such contact can be employed in acid gas enrichment
zone 10. In one or more embodiments, acid gas enrichment zone 10 can be defined within an
acid gas enrichment absorber vessel that is configured to facilitate counter-current contact
between the acid gas from line 12 and the partially-loaded sulfur absorbing solvent from line 14.
Such an acid gas enrichment absorber vessel can comprise an upper inlet for receiving the
partially-loaded sulfur absorbing solvent from line 14 and a lower inlet for receiving the acid gas
from line 12. In one or more embodiments, acid gas enrichment zone 0 can be defined within a
packed or tray column. If a tray column is employed, acid gas enrichment zone 0 can comprise
a plurality of contact-enhancing valve trays. In one or more embodiments, acid gas enrichment
zone 10 can have in the range of from about 1 to about 30 valve trays. In other embodiments,
when a packed column is employed, acid gas enrichment zone 10 can have in the range of from
about 1 to about 10 theoretical plates.
[0018] Reaction conditions employed in acid gas enrichment zone 10 can be any suitable
conditions for achieving acid gas enrichment as described herein. In one or more embodiments,
the temperature employed in acid gas enrichment zone 0 can be in the range of from about 25 to
about 85 °C. Additionally, the pressure employed in acid gas enrichment zone 10 can be in the
range of from about 0 to about 200 kPag. Furthermore, the above-mentioned acid gas from line
12 and the partially-loaded sulfur absorbing solvent from line 14 can be present in acid gas
enrichment zone 10 in a molar ratio in the range of from about 0.01 : 1 to about 1:1, in the range
of from about 0.03:1 to about 0.3:1, or in the range of from 0.05:1 to 0.1 5 :1.
[0019] As is discussed in greater detail below, the partially-loaded sulfur absorbing solvent
in line 14 can be a stream resulting from treating a hydrogenated Claus tail gas and acid gas
enrichment off-gas with a regenerated sulfur absorbing solvent. As used herein, the term
partially-loaded sulfur absorbing solvent shall denote a sulfur absorbing solvent comprising
hydrogen sulfide. In one or more embodiments, the partially-loaded sulfur absorbing solvent in
line 14 can have a concentration of hydrogen sulfide of at least 0.01 mole percent, at least 0 .1
mole percent, or at least 0.5 mole percent. Additionally, the partially-loaded sulfur absorbing
solvent in line 14 can have a concentration of hydrogen sulfide in the range of from about 0.01 to
about 0 mole percent, in the range of from about 0.05 to about 5 mole percent, or in the range of
from 0.1 to 1 mole percent. Furthermore, the partially-loaded sulfur absorbing solvent in line 4
can have a concentration of hydrogen sulfide of less than 5 mole percent, less than 3 mole
percent, less than 1 mole percent, less than 0.8 mole percent, less than 0.6 mole percent, less than
0.5 mole percent, less than 0.4 mole percent, or less than 0,3 mole percent.
[0020] Furthermore, the partially-loaded sulfur absorbing solvent in line 14 can comprise a
sulfur absorbing solvent. Any sulfur absorbing solvent known or hereafter discovered in the art
suitable for absorbing one or more types of sulfur compounds from a sulfur-containing stream
can be employed as the sulfur absorbing solvent in various embodiments of the present
invention. In one or more embodiments, the sulfur absorbing solvent can be a selective sulfur
absorbing solvent that preferentially absorbs hydrogen sulfide. Examples of suitable sulfur
absorbing solvents include, but are not limited to, alkanolamines, such as, for example,
monoethanol amine ("MEA"), diethanolamine ("DEA"), methyldiethanolamine ("MDEA"),
diisopropylamine ("DIPA"), and diglycolamine ("DGA"), or mixtures of two or more thereof.
An example of a suitable commercially available sulfur absorbing solvent includes, but is not
limited to, FLEXSORB, available from ExxonMobil Research and Engineering Company
(Fairfax, VA). In one embodiment, the sulfur absorbing solvent can comprise MDEA.
[0021] In one or more embodiments, the partially-loaded sulfur absorbing solvent in line 4
can have a concentration of sulfur absorbing solvent of at least 1 mole percent, at least 5 mole
percent, or at least 10 mole percent. Additionally, the partially-loaded sulfur absorbing solvent
in line 14 can have a concentration of sulfur absorbing solvent in the range of from about 1 to
about 20 mole percent, in the range of from about 5 to about 15 mole percent, or in the range of
from 0 to mole percent.
[0022] As mentioned above, acid gas enrichment zone 10 can operate to facilitate contact
between the acid gas introduced via line 12 and the partially-loaded sulfur absorbing solvent
introduced via line 14. Such contact between the acid gas and the partially-loaded sulfur
absorbing solvent can cause the partially-loaded sulfur absorbing solvent to absorb hydrogen
sulfide and optionally other sulfur compounds from the acid gas thereby forming a hydrogen
sulfide depleted off-gas and a hydrogen sulfide rich sulfur absorbing solvent. The hydrogen
sulfide depleted off-gas can be withdrawn from acid gas enrichment zone 10 via line 16, while
the hydrogen sulfide rich sulfur absorbing solvent can be withdrawn via line 18.
[0023] In one or more embodiments, contact between the partially-loaded sulfur absorbing
solvent from line 14 and the acid gas from line 2 can be sufficient to remove at least 60, at least
80, or at least 95 mole percent of hydrogen sulfide from the acid gas. Additionally, contact
between the partially-loaded sulfur absorbing solvent from line 14 and the acid gas from line 12
can be sufficient to remove in the range of from about 60 to about 100, in the range of from
about 80 to about 100, or in the range of from 95 to 100 mole percent of hydrogen sulfide from
the acid gas.
[0024] It should be noted, however, that according to certain aspects of the present invention,
the amount of hydrogen sulfide allowed to exit acid gas enrichment zone 0 with the hydrogen
sulfide depleted off-gas in line 16 can be higher than in some other conventional acid gas
enrichment processes. Without wishing to be bound by theory, it is believed that this, in
combination with various other embodiments of the invention, allows for synergistic energy
savings as well as lower capital costs without sacrificing overall sulfur recovery. Accordingly, in
one or more embodiments, the hydrogen sulfide depleted off-gas in line 6 can have a hydrogen
sulfide concentration of at least 0.1, at least 0.2, at least 0,3, at least 0,4, at least 0.5, at least 0.6,
at least 0.7, at least 0.8, at least 0.9, at least 1, at least 1.1, at least 1.2, at least 1.3, at least 1.4, or
at least 1.5 mole percent. In other various embodiments, the hydrogen sulfide depleted off-gas in
line 16 can have a hydrogen sulfide concentration in the range of from about 0.01 to about 10
mole percent, in the range of from about 0.05 to about 5 mole percent, or in the range of from 0.1
to 2 mole percent. Furthermore, at least 0. 1, at least 0.5, at least 1.0, at least 1.5, or at least 2.0
mole percent of the hydrogen sulfide in the acid gas from line 2 can exit acid gas enrichment
zone 10 with the hydrogen sulfide depleted off-gas in line 6.
[0025] The hydrogen sulfide depleted off-gas in line 6 can also comprise COS and/or one or
more types of mercaptans, such as methyl mercaptan and ethyl mercaptan. In one or more
embodiments, the hydrogen sulfide depleted off-gas in line 16 can have a combined
concentration of COS and one or more types of mercaptans of at least 0.01, at least 0.037, at least
0 . 1, at least 0.2, or at least 0.3 mole percent. Furthermore, the hydrogen sulfide depleted off-gas
in line 16 can have individual concentrations of COS and one or more types of mercaptans of at
least 0.01 , at least 0.037, at least 0.1, at least 0.2, or at least 0.3 mole percent each. Additionally,
the hydrogen sulfide depleted off-gas in line 1 can have a combined concentration of COS and
one or more types of mercaptans in the range of from about 0.01 to about 10 mole percent, in the
range of from about 0.05 to about 5 mole percent, or in the range of from 0.1 to 1 mole percent.
Moreover, the hydrogen sulfide depleted off-gas in line 16 can have individual concentrations of
COS and one or more types of mercaptans in the range of from about 0.01 to about 0 mole
percent, in the range of from about 0.05 to about 5 mole percent, or in the range of from 0 .1 to 1
mole percent each. In one or more embodiments, at least 80, at least 90, or at least 95 mole
percent of COS in the acid gas from line 12 can exit acid gas enrichment zone 10 with the
hydrogen sulfide depleted off-gas in line 16. Additionally, at least 80, at least 90, or at least 95
mole percent of mercaptans in the acid gas from line 12 can exit acid gas enrichment zone 10
with the hydrogen sulfide depleted off-gas in line 16.
[0026] The hydrogen sulfide depleted off-gas in line 16 can also comprise a variety of other
components, including, but not limited to, carbon dioxide, water, and one or more types of
hydrocarbons. In one or more embodiments, the hydrogen sulfide depleted off-gas in line 16 can
comprise carbon dioxide in a concentration of at least 60, at least 70, at least 80, or at least 90
mole percent. Additionally, the hydrogen sulfide depleted off-gas in line 16 can comprise carbon
dioxide in an amount in the range of from about 50 to about 99 mole percent, or in the range of
from 75 to 95 mole percent.
[0027] As mentioned above, a hydrogen sulfide rich sulfur absorbing solvent can be
withdrawn from acid gas enrichment zone 10 via line 18 . The hydrogen sulfide rich sulfur
absorbing solvent in line 18 can comprise sulfur absorbing solvent, carbon dioxide, hydrogen
sulfide, and other sulfur compounds, such as, for example, methyl mercaptan, ethyl mercaptan,
and COS. In one or more embodiments, the hydrogen sulfide rich sulfur absorbing solvent in
line 8 can comprise sulfur absorbing solvent in an amount in the range of from about 5 to about
15 mole percent. Additionally, the hydrogen sulfide rich sulfur absorbing solvent in line 18 can
comprise hydrogen sulfide in an amount of at least 1 mole percent, at least 2 mole percent, at
least 2.6 mole percent, at least 4 mole percent, or at least 5 mole percent, Furthermore, the
hydrogen sulfide rich sulfur absorbing solvent in line 18 can comprise hydrogen sulfide in an
amount of less than 20 mole percent, less than 15 mole percent, or less than 0 mole percent.
Also, the hydrogen sulfide rich sulfur absorbing solvent in line 18 can comprise hydrogen sulfide
in an amount in the range of from about 0.1 to about 10 mole percent. Furthermore, the
hydrogen sulfide rich sulfur absorbing solvent in line 18 can have a combined concentration of
COS and one or more types of mercaptans in the range of from about 0 to about 0.1 mole
percent. Moreover, the hydrogen sulfide rich sulfur absorbing solvent in line 18 can have
individual concentrations of COS and one or more types of mercaptans in the range of from
about 0 to about 0.1 mole percent.
[0028] The hydrogen sulfide rich sulfur absorbing solvent in line 8 can be primarily in the
liquid phase. In one or more embodiments, at least 80, at least 90, at least 95, or at least 99 mole
percent of the hydrogen sulfide rich sulfur absorbing solvent in line 18 can be in the liquid phase.
Furthermore, the hydrogen sulfide rich sulfur absorbing solvent in line 8 can have a pressure in
the range of from about 0 to about 200 kPag. Additionally, the hydrogen sulfide rich sulfur
absorbing solvent in line 18 can have a temperature in the range of from about 40 to about 80 °C.
[0029] After exiting acid gas enrichment zone 10, the hydrogen sulfide rich sulfur absorbing
solvent in line 18 can be pumped by acid gas enrichment pump 20 to acid gas enrichment heat
exchanger 22 via line 24. Acid gas enrichment heat exchanger 22 can be operable to increase the
temperature of the hydrogen sulfide rich sulfur absorbing solvent in line 24. In one or more
embodiments, acid gas enrichment heat exchanger 22 can increase the temperature of the
hydrogen sulfide rich sulfur absorbing solvent by at least 10 to about 50 °C. Acid gas
enrichment heat exchanger 22 can be any type of heat exchanger known or hereafter discovered
in the art. In one or more embodiments, acid gas enrichment heat exchanger 22 can comprise a
shell and tube type heat exchanger.
[0030] Following heat exchange, a preheated hydrogen sulfide rich sulfur absorbing solvent
can be withdrawn from acid gas enrichment heat exchanger 22 via line 26. In one or more
embodiments, the preheated hydrogen sulfide rich sulfur absorbing solvent can have a
temperature in the range of from about 50 to about 150 °C. The preheated hydrogen sulfide rich
sulfur absorbing solvent in line 26 can then be introduced into regeneration zone 28.
[0031] Once in regeneration zone 28, the preheated hydrogen sulfide rich sulfur absorbing
solvent can undergo a regeneration process to remove at least a portion of the hydrogen sulfide
contained therein thereby creating an enriched hydrogen sulfide off-gas and a regenerated sulfur
absorbing solvent. In one or more embodiments, regeneration zone 28 can operate to remove at
least 50, at least 70, at least 90, or at least 95 mole percent of the hydrogen sulfide from the
incoming hydrogen sulfide rich sulfur absorbing solvent. Additionally, regeneration zone 28 can
operate to remove at least 50, at least 70, at least 90, or at least 95 mole percent of carbon
dioxide from the hydrogen sulfide rich sulfur absorbing solvent. Any regeneration process
known or hereafter discovered in the art can be employed that is suitable for removing at least a
portion of a hydrogen sulfide component from a sulfur absorbing solvent. In one or more
embodiments, regeneration of the hydrogen sulfide rich sulfur absorbing solvent can be
accomplished by stripping hydrogen sulfide from the sulfur absorbing solvent. Such stripping
can be accomplished via steam stripping. Accordingly, in one or more embodiments,
regeneration zone 28 can be defined within a vessel suitable for steam stripping operations. Heat
for the stripping process can be supplied to regeneration zone 28 via reboiler 30.
[0032] Reaction conditions employed in regeneration zone 28 can be any suitable conditions
for achieving sulfur absorbing solvent regeneration as described herein. In one or more
embodiments, the temperature employed in regeneration zone 28 can be in the range of from
about 75 to about 175 °C. Additionally, the pressure employed in regeneration zone 28 can be in
the range of from about 0 to about 200 kPag.
[0033] Following regeneration, a regenerated sulfur absorbing solvent can be withdrawn
from regeneration zone 28 via line 32. The regenerated sulfur absorbing solvent in line 32 can
have a concentration of sulfur absorbing solvent of at least 5 mole percent. Additionally, the
regenerated sulfur absorbing solvent in line 32 can have a concentration of hydrogen sulfide of
less than 0.1 mole percent. Furthermore, the regenerated sulfur absorbing solvent in line 32 can
have a combined concentration of COS and one or more types of mercaptans of less than 0.01
mole percent. In one or more embodiments, the regenerated sulfur absorbing solvent in line 32
can have a temperature in the range of from about 75 to about 175 °C. Additionally, the
regenerated sulfur absorbing solvent in line 32 can have a pressure in the range of from about 0
to about 200 kPag.
[0034] After being withdrawn from regeneration zone 28, the regenerated sulfur absorbing
solvent in line 32 can be pumped by pump 34 to acid gas enrichment heat exchanger 22 to heat
the incoming hydrogen sulfide rich sulfur absorbing solvent from line 24. Thereafter, a cooled
regenerated sulfur absorbing solvent can be further cooled in cooler 36, filtered through filter 38,
and routed to tail gas treatment zone 40 via line 42. Use of the regenerated sulfur absorbing
solvent in tail gas treatment zone 40 is discussed in greater detail below.
[0035] The enriched hydrogen sulfide off-gas generated in regeneration zone 28 can be
withdrawn via line 44. The enriched hydrogen sulfide off-gas in line 44 can be routed to reflux
condenser 46, which produces a condensed reflux stream and an enriched hydrogen sulfide
stream, The condensed reflux stream can be withdrawn from reflux condenser 46 via line 48 and
routed back to regeneration zone 28 to be employed as reflux. The enriched hydrogen sulfide
stream can be withdrawn from reflux condenser 46 via line 50 and routed to sulfur recovery
zone 52.
[0036] The enriched hydrogen sulfide stream in line 50 can comprise several components,
including, but not limited to, hydrogen sulfide, carbon dioxide, COS, one or more types of
mercaptans, and water. In one or more embodiments, the enriched hydrogen sulfide stream in
line 50 can have a concentration of hydrogen sulfide of at least 10, at least 20, at least 30, or at
least 40 mole percent. Additionally, the enriched hydrogen sulfide stream in line 50 can have a
hydrogen sulfide concentration in the range of from about 10 to about 90 mole percent, in the
range of from about 20 to about 70 mole percent, or in the range of from 30 to 50 mole percent.
In one or more embodiments, the enriched hydrogen sulfide stream in line 50 can have a carbon
dioxide concentration of at least 10, at least 20, at least 30, or at least 40 mole percent.
Furthermore, the enriched hydrogen sulfide stream in line 50 can have a carbon dioxide
concentration in the range of from about 10 to about 90 mole percent, in the range of from about
20 to about 70 mole percent, or in the range of from 30 to 50 mole percent. In one or more
embodiments, the enriched hydrogen sulfide stream in line 50 can have a combined
concentration of COS and one or more types of mercaptans of less than 0.5, less than 0.1, or less
than 0.05 mole percent. In one or more embodiments, the enriched hydrogen sulfide stream in
line 50 can have individual concentrations of COS and one or more types of mercaptans of less
than 0.5, less than 0.1, or less than 0.05 mole percent each.
[0037] As mentioned above, the enriched hydrogen sulfide stream in line 50 can be fed to
sulfur recovery zone 52. Sulfur recovery zone 52 can operate to convert at least a portion of
hydrogen sulfide from the enriched hydrogen sulfide stream in line 50 to elemental sulfur. In
one or more embodiments, sulfur recovery zone 52 can operate to convert at least 50, at least 70,
at least 90, at least 95, at least 99, at least 99.5, or at least 99.9 mole percent of the hydrogen
sulfide from the enriched hydrogen sulfide stream in line 50 to elemental sulfur. Additionally,
recovered elemental from sulfur recovery zone 52 can represent at least 70, at least 80, at least
90, at least 95, at least 99, at least 99.5, or at least 99 9 mole percent of the combined amount of
sulfur compounds and hydrogen sulfide in the acid gas in line 12. Any means known or
hereafter discovered in the art for converting hydrogen sulfide to elemental sulfur can be
employed in sulfur recovery zone 52. In one or more embodiments, sulfur recovery zone 52 can
employ a Claus sulfur recovery process, as will be described in greater detail below with
reference to FIG, 2.
[0038] Referring still to FIG. 1, following sulfur recovery, a sulfur rich stream can be
withdrawn from sulfur recovery zone 52 via line 54, and a tail gas can be withdrawn via line 56.
The sulfur rich stream in line 54 can contain at least 90, at least 99, or at least 100 mole percent
elemental sulfur. In one or more embodiments, the amount of sulfur recovered via sulfur
recovery zone 52 can amount to recovery of a majority of all the sulfur compounds in the acid
gas in line 12. In other words, a sulfur recovery system according to various embodiments of the
invention can operate to recover as elemental sulfur greater than 50 weight percent of all
incoming sulfur compounds (e.g., hydrogen sulfide, COS, and mercaptans) in the acid gas in line
12. In other embodiments, the sulfur recovery system can recover as elemental sulfur at least 70,
at least 90, at least 95, at least 99, or at least 99.9 weight percent of all incoming sulfur
compounds in the acid gas in line 12. Additionally, such sulfur recovery can be achieved over a
time-averaged basis. Thus, in one or more embodiments, the above-listed minimum sulfur
recoveries can each be determined as the average sulfur recovery measured over a period of at
least 1 hour, at least 12 hours, at least 1 day, at least 0 days, or at least 20 days. Any timeaverage
determination herein shall be based on a minimum of 5 measurements timed equally
over the applicable time period.
[0039] The tail gas in line 56 can comprise a variety of components, including, but not
limited to, hydrogen sulfide, carbon disulfide, COS, sulfur dioxide, carbon dioxide, carbon
monoxide, and water. In one or more embodiments, the tail gas in line 56 can have a carbon
dioxide concentration of at least 5, at least 10, or at least 20 mole percent. Additionally, the tail
gas in line 56 can have a carbon dioxide concentration in the range of from about 5 to about 50
mole percent, in the range of from about 0 to about 40 mole percent, or in the range of from 20
to 30 mole percent.
[0040] In one or more embodiments, the tail gas in line 56 can have a hydrogen sulfide
concentration of at least 0.1, at least 0.4, or at least 0.8 mole percent. In other embodiments, the
tail gas in line 56 can have a hydrogen sulfide concentration of less than 5, less than 3, or less
than 2 mole percent. Additionally, the tail gas in line 56 can have a hydrogen sulfide
concentration in the range of from about 0.1 to about 5 mole percent, in the range of from about
0.4 to about 2 mole percent, or in the range of from 0.8 to 1.2 mole percent,
[0041] In one or more embodiments, the tail gas in line 56 can have a COS concentration of
at least 0.01, at least 0.05, at least 0.1, or at least 0.2 mole percent. In other embodiments, the
tail gas in line 56 can have a COS concentration of less than 5, less than 3, less than 1, or less
than 0.5 mole percent. Additionally, the tail gas in line 56 can have a COS concentration in the
range of from about 0.01 to about 5 mole percent, in the range of from about 0.05 to about 3
mole percent, in the range of from about 0.1 to about 1 mole percent, or in the range of from 0.2
to 0.5 mole percent.
[0042] n one or more embodiments, the tail gas in line 56 can have a sulfur dioxide
concentration of at least 0.01, at least 0.05, at least 0.1, or at least 0.2 mole percent. In other
embodiments, the tail gas in line 56 can have a sulfur dioxide concentration of less than 5, less
than 3, less than 1, or less than 0.5 mole percent. Additionally, the tail gas in line 56 can have a
sulfur dioxide concentration in the range of from about 0.01 to about 5 mole percent, in the range
of from about 0.05 to about 3 mole percent, in the range of from about 0 .1 to about 1 mole
percent, or in the range of from 0.2 to 0.5 mole percent.
[0043] The tail gas in line 56 can be primarily in the vapor phase. In one or more
embodiments, at least 70, at least 80, at least 90, or at least 99 mole percent of the tail gas in line
56 can be in the vapor phase. Additionally, the tail gas in line 56 can have a temperature in the
range of from about 50 to about 250 °C, or in the range of from 100 to 200 °C. Furthermore, the
tail gas in line 56 can have a pressure in the range of from about 0 to about 100 kPag, or in the
range of from 20 to 70 kPag.
[0044] Following withdrawal from sulfur recovery zone 52, at least a portion of the tail gas
in line 56 can be routed via line 58 to mixing zone 60, while the remaining portion can be routed
to incineration zone 62 via line 64. The tail gas portion from line 64 can be incinerated and
passed to stack 66 for venting to the atmosphere. In one or more embodiments, the portion of the
tail gas routed to mixing zone 60 can constitute in the range of from about 0 to about 100 mole
percent of the total tail gas withdrawn from sulfur recovery zone 52.
[0045] The tail gas introduced into mixing/heating zone 60 can be combined therein the with
hydrogen sulfide depleted off-gas from line 16, which was withdrawn from acid gas enrichment
zone 0. Mixing zone 60 can operate to heat and mix the hydrogen sulfide depleted off-gas from
line 16 with the tail gas from line 58. Any methods known or hereafter discovered in the art for
mixing and heating a plurality of gases can be employed in mixing/heating zone 60. In one or
more embodiments, mixing/heating zone 60 can comprise a mixing unit along with an inline
burner or an indirect heater. In addition to the hydrogen sulfide depleted off-gas and tail gas, a
fuel gas, air stream, and/or steam can be fed to mixing zone 60 in order to combust and heat the
incoming hydrogen sulfide depleted off-gas and tail gas.
[0046] In one or more embodiments, the resulting mixed and heated gas can be withdrawn
from mixing zone 60 via line 68 as a hydrogenation feed stream. The hydrogenation feed stream
in line 68 can comprise a variety of components, including, but not limited to, hydrogen sulfide,
carbon disulfide, COS, sulfur dioxide, carbon dioxide, and water. In one or more embodiments,
the hydrogenation feed stream in line 68 can have a carbon dioxide concentration of at least 10,
at least 20, or at least 30 mole percent. Additionally, the hydrogenation feed stream in line 68
can have a carbon dioxide concentration in the range of from about 10 to about 70 mole percent,
in the range of from about 20 to about 60 mole percent, or in the range of from 30 to 50 mole
percent.
[0047J In one or more embodiments, the hydrogenation feed stream in line 68 can have a
hydrogen sulfide concentration of at least 0.1, at least 0.3, or at least 0.6 mole percent. In other
embodiments, the hydrogenation feed stream in line 68 can have a hydrogen sulfide
concentration of less than 4, less than 2, or less than 1 mole percent. Additionally, the
hydrogenation feed stream in line 68 can have a hydrogen sulfide concentration in the range of
from about 0. to about 4 mole percent, in the range of from about 0.3 to about 2 mole percent,
or in the range of from 0.6 to 1 mole percent.
[0048] In one or more embodiments, the hydrogenation feed stream in line 68 can have a
combined concentration of COS and one or more types of mercaptans of at least 0.01, at least
0.037, at least 0.05, at least 0. 1, or at least 0.2 mole percent. In other embodiments, the
hydrogenation feed stream in line 68 can have a combined concentration of COS and one or
more types of mercaptans of less than 5, less than 3, less than 1, or less than 0.5 mole percent.
Additionally, the hydrogenation feed stream in line 68 can have a combined concentration of
COS and one or more types of mercaptans in the range of from about 0.01 to about 5 mole
percent, in the range of from about 0.05 to about 3 mole percent, in the range of from about 0.1
to about 1 mole percent, or in the range of from 0.2 to 0.5 mole percent.
[0049] In one or more embodiments, the hydrogenation feed stream in line 68 can have
individual concentrations of COS and one or more types of mercaptans of at least 0.01, at least
0.05, at least 0.1, or at least 0.2 mole percent each. In other embodiments, the hydrogenation
feed stream in line 68 can have individual concentrations of COS and one or more types of
mercaptans of less than 5, less than 3, less than 1, or less than 0.5 mole percent each.
Additionally, the hydrogenation feed stream in line 68 can have individual concentrations of
COS and one or more types of mercaptans in the range of from about 0.01 to about 5 mole
percent, in the range of from about 0.05 to about 3 mole percent, in the range of from about 0.1
to about 1 mole percent, or in the range of from 0.2 to 0.5 mo e percent each.
[0050] In one or more embodiments, the hydrogenation feed stream in line 68 can have a
sulfur dioxide concentration of at least 0.01, at least 0.05, or at least 0.1 mole percent. In other
embodiments, the hydrogenation feed stream in line 68 can have a sulfur dioxide concentration
of less than 5, less than 3, less than 1, or less than 0.5 mole percent. Additionally, the
hydrogenation feed stream in line 68 can have a sulfur dioxide concentration in the range of from
about 0.01 to about 3 mole percent, in the range of from about 0.05 to about 1 mole percent, or in
the range of from 0.1 to 0.3 mole percent.
[0051] In addition to the foregoing components, the hydrogenation feed stream in line 68 can
contain hydrogen and carbon monoxide, at least partly originating from gases produced during
combustion in the above-mentioned inline burner. In one or more embodiments, the
hydrogenation feed stream in line 68 can have a hydrogen concentration of at least 0.5, at least 1,
at least 1.5, or at least 2 mole percent. Additionally, the hydrogenation feed stream in line 68 can
have a hydrogen concentration in the range of from about 0.5 to about 20 mole percent, in the
range of from about 1 to about 10 mole percent, in the range of from about 1.5 to about 5 mole
percent, or in the range of from 2 to 3 mole percent. In one or more embodiments, the
hydrogenation feed stream in line 68 can have a carbon monoxide concentration of at least 0.1, at
least 0.4, or at least 0.7 mole percent. Additionally, the hydrogenation feed stream in line 68 can
have a carbon monoxide concentration in the range of from about 0.1 to about 5 mole percent, in
the range of from about 0.4 to about 3 mole percent, or in the range of from 0.7 to 1. 1 mole
percent.
[0052] The hydrogenation feed stream in line 68 can be primarily in the vapor phase. In one
or more embodiments, at least 70, at least 80, at least 90, or at least 99 mole percent of the
hydrogenation feed stream in line 68 can be in the vapor phase. Additionally, the hydrogenation
feed stream in line 68 can have a temperature in the range of from about 100 to about 500 °C, in
the range of from about 200 to about 400 °C, or in the range of from 250 to 350 °C.
Furthermore, the hydrogenation feed stream in line 68 can have a pressure in the range of from
about 0 to about 100 kPag, or in the range of from 20 to 70 kPag.
[0053] Following withdrawal from mixing zone 60, the hydrogenation feed stream in line 68
can be introduced into hydrogenation zone 70. Hydrogenation zone 70 can operate to convert at
least a portion of various sulfur compounds therein to hydrogen sulfide. For example,
hydrogenation zone 70 can operate to convert at least a portion of COS, mercaptans, sulfur
vapor, and/or sulfur dioxide to hydrogen sulfide. In one or more embodiments, hydrogenation
zone 70 can operate to convert at least 50, at least 70, or at least 90 mole percent of COS from
the hydrogenation feed stream to hydrogen sulfide. Additionally, hydrogenation zone 70 can
operate to convert at least 50, at least 70, or at least 90 mole percent of all mercaptans (e.g.,
methyl mercaptan and/or ethyl mercaptan) from the hydrogenation feed stream to hydrogen
sulfide. Furthermore, hydrogenation zone 70 can operate to convert at least 50, at least 70, or at
least 90 mole percent of sulfur dioxide from the hydrogenation feed stream to hydrogen sulfide.
[0054] Any methods known or hereafter discovered in the art for converting the abovedescribed
sulfur compounds to hydrogen sulfide can be employed in hydrogenation zone 70. In
one or more embodiments, consumption of carbon monoxide and hydrogen from the incoming
hydrogenation feed stream in line 68 along with use of a hydrogenation catalyst can be employed
to facilitate conversion to hydrogen sulfide in hydrogenation zone 70. Examples of
commercially available hydrogenation catalysts suitable for use in hydrogenation zone 70
include, but are not limited to, CRITERION-234 or -534 (available from Criterion Catalysts &
Technologies, Houston, TX) and AXENS TG-103 or - 07 (available from Axens 1FP Group
Technologies, Houston, TX). In one or more embodiments, the hydrogenation catalyst
comprises a Group VI and/or Group VIII metal sulfided catalyst.
[0055] Reaction conditions employed in hydrogenation zone 70 can be any suitable
conditions for the above-described conversion of sulfur compounds to hydrogen sulfide. In one
or more embodiments, the temperature employed in hydrogenation zone 70 can be in the range
of from about 200 to about 350 °C. Additionally, the pressure employed in hydrogenation zone
70 can be in the range of from about 0 to about 200 kPag.
[0056] Following hydrogenation in hydrogenation zone 70, a hydrogenated stream can be
withdrawn via line 72. The hydrogenated stream in line 72 can comprise a variety of
components, including, but not limited to, hydrogen sulfide, carbon disulfide, COS, sulfur
dioxide, carbon dioxide, carbon monoxide, and water. In one or more embodiments, the
hydrogenated stream in line 72 can have a carbon dioxide concentration of at least 5, at least 10,
or at least 15 mole percent. Additionally, the hydrogenated stream in line 72 can have a carbon
dioxide concentration in the range of from about 5 to about 40 mole percent, in the range of from
about 10 to about 30 mole percent, or in the range of from 5 to 20 mole percent. In one or more
embodiments, the hydrogenated stream in line 72 can have a hydrogen sulfide concentration of at
least 5, at least 0, or at least 15 mole percent. Additionally, the hydrogenated stream in line 72
can have a hydrogen sulfide concentration in the range of from about 5 to about 40 mole percent,
in the range of from about 10 to about 30 mole percent, or in the range of from 15 to 20 mole
percent. In one or more embodiments, the hydrogenated stream in line 72 can have individual
concentrations of each of COS, sulfur dioxide, and one or more types of mercaptans (e.g., methyl
mercaptan and/or ethyl mercaptan) of less than 0,1, less than 0.05, less than 0.01, or less than
0.001 mole percent. In other embodiments, the hydrogenated stream in line 72 can have
substantially no COS, sulfur dioxide, and/or one or more types of mercaptans (e.g., methyl
mercaptan and/or ethyl mercaptan).
[0057] The hydrogenated stream in line 72 can be primarily in the vapor phase. In one or
more embodiments, at least 70, at least 80, at least 90, or at least 99 mole percent of the
hydrogenated stream in line 72 can be in the vapor phase. Additionally, the hydrogenated stream
in line 72 can have a temperature in the range of from about 50 to about 400 °C, or in the range
of from 250 to 350 °C. Furthermore, the hydrogenated stream in line 72 can have a pressure in
the range of from about 200 to about 500 kPag, or in the range of from 300 to 400 kPag.
[0058] Following withdrawal from hydrogenation zone 70, the hydrogenated stream in line
72 can be introduced into waste heat boiler 74. Waste heat boiler 74 can operate to at least
partially cool the incoming hydrogenated stream from line 72, while recovering energy in the
form of heat. Any known or hereafter discovered waste heat boiler configuration can be
employed for waste heat boiler 74. Following treatment in waste heat boiler 74, a cooled
hydrogenated stream can be withdrawn via line 76 as a quench feed stream. In various
embodiments, waste heat boiler 74 can be bypassed,
[0059] The quench feed stream in line 76 can have substantially the same composition as the
hydrogenated stream in line 72, described above. Additionally, the quench feed stream in line 76
can be primarily in the vapor phase. In one or more embodiments, at least 70, at least 80, at least
90, or at least 99 mole percent of the quench feed stream in line 76 can be in the vapor phase.
Additionally, the quench feed stream in line 76 can have a temperature in the range of from
about 100 to about 200 °C. Furthermore, the quench feed stream in line 76 can have a pressure
in the range of from about 0 to about 200 kPag.
[0060] Following withdrawal from waste heat boiler 74, the quench feed stream in line 76
can be introduced into quenching zone 78. Quenching zone 78 can operate to facilitate contact
between relatively cooler water and the incoming quench feed stream from line 76 thereby
cooling the quench feed stream from line 76. In one or more embodiments, the quench feed
stream can undergo a temperature reduction in quenching zone 78 of at least 50 °C, at least
75 °C, or at least 100 °C.
[0061] Any methods known or hereafter discovered for quenching a substantially vapor
phase stream with water can be employed in quenching zone 78. In one or more embodiments,
quenching zone 78 can be defined within a quench column employing a bottoms recirculation
system 80. In one or more embodiments, the water employed in quenching zone 78 can have a
temperature in the range of from about 25 to about 45 °C. Additionally, the water and the
quench feed stream from line 76 can be present in quenching zone 78 in a molar ratio in the
range of from about 5 to about 15.
[0062] Following treatment in quenching zone 78, a tail gas treatment feed stream can be
withdrawn via line 82. The tail gas treatment feed stream in line 82 can have substantially the
same composition as the quench feed stream in line 76, described above. Additionally, the tail
gas treatment feed stream in line 82 can be primarily in the vapor phase. In one or more
embodiments, at least 70, at least 80, at least 90, or at least 99 mole percent of the tail gas
treatment feed stream in line 82 can be in the vapor phase. Furthermore, the tail gas treatment
feed stream in line 82 can have a temperature in the range of from about 25 to about 45 °C.
Moreover, the tail gas treatment feed stream in line 82 can have a pressure in the range of from
about 0 to about 200 kPag.
[0063] Following withdrawal from quenching zone 78, the tail gas treatment feed stream in
line 82 can be introduced into tail gas treatment zone 40. Tail gas treatment zone 40 can operate
to facilitate contact between the tail gas treatment feed stream from line 82 and the regenerated
sulfur absorbing solvent introduced via line 42, as mentioned above. Such contact can allow
hydrogen sulfide contained in the tail gas treatment feed stream from line 82 to be absorbed by
the regenerated sulfur absorbing solvent from line 42 thereby producing a partially-loaded sulfur
absorbing solvent and a tail gas treatment off-gas. In one or more embodiments, contact between
the regenerated sulfur absorbing solvent from line 42 and the tail gas treatment feed stream from
line 82 can be sufficient to remove at least 90, at least 95, or at least 99.9 mole percent of
hydrogen sulfide from the tail gas treatment feed stream. Additionally, contact between the
regenerated sulfur absorbing solvent from line 42 and the tail gas treatment feed stream from line
82 can be sufficient to remove in the range of from about 90 to about 100, in the range of from
about 95 to about 100, or in the range of from 99 to 100 mole percent of hydrogen sulfide from
the tail gas treatment feed stream.
[0064] Any methods or apparatus known or hereafter discovered in the art suitable to
facilitate such contact can be employed in tail gas treatment zone 40. In one or more
embodiments, tail gas treatment zone 40 can be defined within a tail gas treatment absorber
vessel that is configured to facilitate counter-current contact between the tail gas treatment feed
stream from line 82 and the regenerated sulfur absorbing solvent from line 42. Such a tail gas
treatment absorber vessel can comprise an upper inlet for receiving the regenerated sulfur
absorbing solvent from line 42 and a lower inlet for receiving the tail gas treatment feed stream
from line 82. In one or more embodiments, tail gas treatment zone 40 can be defined within a
packed or tray column. If a tray column is employed, tail gas treatment zone 40 can comprise a
plurality of contact-enhancing valve trays. In one or more embodiments, tail gas treatment zone
40 can have in the range of from about 3 to about 30 valve trays. In other embodiments, when a
packed column is employed, tail gas treatment zone 40 can have in the range of from about 1 to
about 10 theoretical plates.
[0065] Reaction conditions employed in tail gas treatment zone 40 can be any suitable
conditions for achieving tail gas treatment as described herein. In one or more embodiments, the
temperature employed in tail gas treatment zone 40 can be in the range of from about 25 to about
45 °C. Additionally, the pressure employed in tail gas treatment zone 40 can be in the range of
from about 0 to about 200 kPag. Furthermore, the above-mentioned tail gas treatment feed
stream from line 82 and the regenerated sulfur absorbing solvent from line 42 can be present in
tail gas treatment zone 40 in a molar ratio in the range of from about 0.01 to about 1, in the range
of from about 0.1 to about 0.5, or in the range of from 0.15 to 0.25.
[0066] Following treatment in tail gas treatment zone 40, the partially-loaded sulfur
absorbing solvent can be withdrawn via line 84 and pumped by pump 86 via line 14 for use in
acid gas enrichment zone 10, as described above. Although not depicted, the partially-loaded
sulfur absorbing solvent can optionally be cooled prior to being introduced into acid gas
enrichment zone 10 Such cooling can be performed by a cooler or condenser interposed
between pump 86 and acid gas enrichment zone 10. The off-gas produced in tail gas treatment
zone 40 can be withdrawn via line 88. The tail gas treatment off-gas in line 88 can comprise a
variety of components, including, but not limited to, hydrogen sulfide, carbon disulfide, COS,
sulfur dioxide, carbon dioxide, carbon monoxide, and water. In one or more embodiments, the
tail gas treatment off-gas in line 88 can have a carbon dioxide concentration of at least 10, at
least 25, or at least 40 mole percent. Additionally, the tail gas treatment off-gas in line 88 can
have a carbon dioxide concentration in the range of from about 10 to about 90 mole percent, in
the range of from about 25 to about 75 mole percent, or in the range of from 40 to 60 mole
percent. In one or more embodiments, the tail gas treatment off-gas in line 88 can have a
hydrogen sulfide concentration of less than 0.1, less than 0.05, or less than 0.02 mole percent. In
one or more embodiments, the tail gas treatment off-gas in line 88 can have individual
concentrations of each of COS, sulfur dioxide, and one or more types of mercaptans (e.g., methyl
mercaptan and/or ethyl mercaptan) of less than 0.1, less than 0.05, less than 0.01, or less than
0.001 mole percent. In other embodiments, the tail gas treatment off-gas in line 88 can contain
substantially no COS, sulfur dioxide, and/or one or more types of mercaptans (e.g., methyl
mercaptan and/or ethyl mercaptan).
[0067] The tail gas treatment off-gas in line 88 can be primarily in the vapor phase. In one
or more embodiments, at least 70, at least 80, at least 90, or at least 99 mole percent of the tail
gas treatment off-gas in line 88 can be in the vapor phase. Additionally, the tail gas treatment
off-gas in line 88 can have a temperature in the range of from about 0 to about 100 °C, or in the
range of from 20 to 70 °C. Furthermore, the tail gas treatment off-gas in line 88 can have a
pressure in the range of from about 10 to about 50 kPag, or in the range of from 5 to 30 kPag.
[0068] Following withdrawal from tail gas treatment zone 40, the tail gas treatment off-gas
in line 88 can be introduced into incineration zone 62. Incineration zone 62 can operate to
incinerate the tail gas treatment off-gas from line 88. Thereafter, the resulting incinerated gas
can be passed to stack 66 for venting to the atmosphere.
[0069] Referring still to FIG. 1, the foregoing description describes a process where a sulfur
absorbing solvent can circulate from regeneration zone 28 to tail gas treatment zone 40, then
from tail gas treatment zone 40 to acid gas enrichment zone 10, then from acid gas enrichment
zone 0 back to regeneration zone 28. In one or more embodiments, the sulfur absorbing solvent
can have a circulation rate of less than 80 m /hr, less than 70 m /hr, less than 60 m /hr, or less
than 50 m /hr. As used herein, the term "circulation rate" shall denote the time-averaged flow
rate of a sulfur absorbing solvent between at least two process steps, such as, for example, an
acid gas enrichment step, a regeneration step, and/or a tail gas treatment step, such as those
described herein, as measured over a period of one hour by at least 5 equally spaced
measurements.
[0070] Referring now to FIG. 2, a sulfur recovery unit 0 is depicted. Sulfur recovery unit
10 is essentially a Claus sulfur recovery system and can be employed in sulfur recovery zone
52, described above with reference to FIG. 1. During operation of sulfur recovery unit 110, an
enriched hydrogen sulfide stream can initially be introduced via line 112 into thermal reactor
14. The enriched hydrogen sulfide stream 112 can be substantially the same as the enriched
hydrogen sulfide stream in line 50, described above with reference to FIG. 1.
[0071] During Claus sulfur recovery, hydrogen sulfide from the enriched hydrogen sulfide
stream is converted to elemental sulfur by initially oxidizing a portion of the hydrogen sulfide
according to the following reaction:
2 H2S + 3 0 2 - 2 S0 2 + 2 H20
Thereafter, the resulting sulfur dioxide reacts with hydrogen sulfide remaining in the stream to
form elemental sulfur according to the following reaction:
2 H2S + S0 2 - 3 S + 2 H20
[0072] Referring still to FIG. 2, thermal reactor 4 can operate to thermally oxidize the
incoming enriched hydrogen sulfide stream from line 112. The oxidized stream can then be
routed via line 116 to a first Claus condenser 8 where elemental sulfur can be withdrawn as a
condensate via line 120. The sulfur rich stream in line 120 can have substantially the same
composition as the sulfur rich stream in line 54, described above with reference to FIG. 1. The
remaining vapor phase can be withdrawn from first Claus condenser 8 via line 122.
Thereafter, the vapor phase stream in line 122 can be passed through preheater 124 to heat the
stream, which can then be routed via line 126 to first Claus reactor 128.
[0073] In first Claus reactor 128, conversion of hydrogen sulfide to elemental sulfur
continues under catalytic conditions. Catalysts suitable for use in first Claus reactor 128 include
any Claus catalysts known or hereafter discovered in the art. Examples of such catalysts include,
but are not limited to, activated aluminum (III) oxide and titanium (IV) oxide. Following
reaction in first Claus reactor 128, the treated stream can be routed via line 30 to second Claus
condenser 132 where elemental sulfur can be withdrawn as a condensate via line 34. The sulfur
rich stream in line 34 can have substantially the same composition as the sulfur rich stream in
line 54, described above with reference to FIG. . The remaining vapor phase can be withdrawn
from second Claus condenser 132 via line 136. Thereafter, the vapor phase stream in line 136
can be passed through preheater 138 to heat the stream, which can then be routed via line 140 to
second Claus reactor 142.
[0074] In second Claus reactor 142, conversion of hydrogen sulfide to elemental sulfur
continues under catalytic conditions. Catalysts suitable for use in second Claus reactor 142 can
be the same as those described above as being suitable for use in first Claus reactor 128.
Following reaction in second Claus reactor 142, the treated stream can be routed via line 144 to
third Claus condenser 146 where elemental sulfur can be withdrawn as a condensate via line 148.
The sulfur rich stream in line 148 can have substantially the same composition as the sulfur rich
stream in line 54, described above with reference to FIG. 1. The remaining vapor phase can be
withdrawn as a Claus tail gas from third Claus condenser 146 via line 150. The Claus tail gas in
line 150 can have substantially the same composition as the tail gas in line 56, described above
with reference to FIG. 1.
[0075] Although the invention has been described with reference to the embodiments
illustrated in the attached drawing figures, it is noted that equivalents may be employed and
substitutions made herein without departing from the scope of the invention as recited in the
claims.
SELECTED DEFINITIONS
[0076] It should be understood that the following is not intended to be an exclusive list of
defined terms. Other definitions may be provided in the foregoing description accompanying the
use of a defined term in context.
[0077] As used herein, the terms "a," "an," and "the" mean one or more.
[0078] As used herein, the term "and/or," when used in a list of two or more items, means
that any one of the listed items can be employed by itself or any combination of two or more of
the listed items can be employed. For example, if a composition is described as containing
components A, B, and/or C, the composition can contain A alone; B alone; C alone; A and B in
combination; A and C in combination; B and C in combination; or A, B, and C in combination.
[0079] As used herein, the terms "comprising," "comprises," and "comprise" are open-ended
transition terms used to transition from a subject recited before the term to one or more elements
recited after the term, where the element or elements listed after the transition term are not
necessarily the only elements that make up the subject.
[0080] As used herein, the terms "containing," "contains," and "contain" have the same
open-ended meaning as "comprising," "comprises," and "comprise" provided above.
[0081] As used herein, the terms "having," "has," and "have" have the same open-ended
meaning as "comprising," "comprises," and "comprise" provided above.
[0082] As used herein, the terms, "including," "include," and "included" have the same
open-ended meaning as "comprising," "comprises," and "comprise" provided above.
NUMERICAL RANGES
[0083] The present description uses numerical ranges to quantify certain parameters relating
to various embodiments of the invention. It should be understood that when numerical ranges
are provided, such ranges are to be construed as providing literal support for claim limitations
that only recite the lower value of the range as well as claim limitations that only recite the upper
value of the range. For example, a disclosed numerical range of 10 to 100 provides literal
support for a claim reciting "greater than 10" (with no upper bounds) and a claim reciting "less
than 100" (with no lower bounds).
What is claimed is:
1. A process for recovering sulfur from an acid gas comprising hydrogen sulfide,
said method comprising: contacting said acid gas with a partially-loaded sulfur absorbing solvent
in an acid gas enrichment zone to thereby produce a hydrogen sulfide rich sulfur absorbing
solvent and a hydrogen sulfide depleted off-gas, wherein said hydrogen sulfide depleted off-gas
comprises hydrogen sulfide in an amount of at least 0.5 mole percent, wherein prior to said
contacting, said partially-loaded sulfur absorbing solvent comprises hydrogen sulfide in an
amount of at least 0.01 mole percent.
2 . The process of claim 1, wherein said acid gas comprises said hydrogen sulfide in
a concentration of at least 1 mole percent, wherein at least 1.0 mole percent of said hydrogen
sulfide in said acid gas exits said acid gas enrichment zone with said hydrogen sulfide depleted
off-gas.
3. The process of claim 1, wherein said hydrogen sulfide depleted off-gas comprises
hydrogen sulfide in an amount of at least 1.0 mole percent.
4 . The process of claim 1, wherein said acid gas comprises carbonyl sulfide and one
or more types of mercaptans in a combined concentration of at least 0.025 mole percent.
5. The process of claim 4, wherein at least 80 mole percent of said carbonyl sulfide
and said mercaptans in said acid gas exit said acid gas enrichment zone with said hydrogen
sulfide depleted off-gas.
6. The process of claim 4, wherein said mercaptans comprise methyl mercaptan
and/or ethyl mercaptan.
7 . The process of claim 1, wherein said hydrogen sulfide depleted off-gas comprises
carbonyl sulfide and one or more types of mercaptans in a combined concentration of at least
0.037 mole percent.
8. The process of claim 7, further comprising hydrogenating at least a portion of said
hydrogen sulfide depleted off-gas thereby converting at least a portion of said mercaptans and/or
said carbonyl sulfide in said hydrogen sulfide depleted off-gas to hydrogen sulfide.
9. The process of claim 8, further comprising, prior to said hydrogenating,
combining said hydrogen sulfide depleted off-gas with a Claus tail gas produced during a Claus
sulfur recovery process to thereby form a hydrogenation feed stream.
10. The process of claim 9, wherein said hydrogenation feed stream comprises said
mercaptans and said carbonyl sulfide in a combined concentration of at least 0.05 mole percent,
wherein said hydrogenating converts at least 50 mole percent of the combined concentration of
said mercaptans and said carbonyl sulfide in said hydrogenation feed stream to hydrogen sulfide.
11. The process of claim 1, wherein said partially-loaded sulfur absorbing solvent
comprises hydrogen sulfide in an amount of less than 0.6 mole percent.
12. The process of claim 1, wherein said partially-loaded sulfur absorbing solvent is
formed in a tail gas treatment zone upstream of said acid gas enrichment zone by contacting a
regenerated sulfur absorbing solvent with a tail gas treatment feed stream, wherein said tail-gas
treatment feed stream is prepared by hydrogenating a hydrogenation feed stream comprising a
Claus tail gas produced during a Claus sulfur recovery process and at least a portion of said
hydrogen sulfide depleted off-gas.
13. The process of claim 1, wherein said partially-loaded sulfur absorbing solvent
comprises a polyalkanol amine.
14. The process of claim 1, wherein said acid gas and said partially-loaded sulfur
absorbing solvent are present in a molar ratio in the range of from about 0.01 : 1 to about 1: 1 .
5 . The process of claim 1, further comprising routing at least a portion of said
hydrogen sulfide rich sulfur absorbing solvent to a regeneration zone and therein separating at
least a portion of the hydrogen sulfide from said hydrogen sulfide rich sulfur absorbing solvent
thereby forming an enriched hydrogen sulfide stream and a regenerated sulfur absorbing solvent.
16. The process of claim 15, further comprising routing at least a portion of said
enriched hydrogen sulfide stream to a Claus sulfur recovery process, wherein said Claus sulfur
recovery process converts at least a portion of said hydrogen sulfide in said enriched hydrogen
sulfide stream into elemental sulfur thereby generating a sulfur rich stream and a Claus tail gas.
17. The process of claim 1, wherein said hydrogen sulfide rich sulfur absorbing
solvent has a hydrogen sulfide content of at least 2.6 mole percent.
18 . The process of claim 1, wherein said acid gas further comprises a plurality of
sulfur compounds in addition to said hydrogen sulfide, wherein said sulfur recovery process
recovers as elemental sulfur at least 99.5 weight percent of the total amount of said sulfur
compounds and said hydrogen sulfide from said acid gas.
19. A process for recovering sulfur from an acid gas comprising hydrogen sulfide,
said process comprising:
(a) contacting said acid gas in an acid gas enrichment zone with a partially-loaded
sulfur absorbing solvent to thereby produce a hydrogen sulfide rich sulfur absorbing solvent and
a hydrogen sulfide depleted off-gas;
(b) removing at least a portion of said hydrogen sulfide from said hydrogen sulfide
rich sulfur absorbing solvent to thereby produce an enriched hydrogen sulfide stream and a
regenerated sulfur absorbing solvent; and
(c) contacting at least a portion of said regenerated sulfur absorbing solvent with a
hydrogenated stream containing hydrogen sulfide to thereby produce said partially-loaded sulfur
absorbing solvent,
wherein the hydrogen sulfide content of said hydrogen sulfide rich sulfur absorbing
solvent is at least 2.6 mole percent.
20. The process of claim 19, wherein said acid gas comprises said hydrogen sulfide in
a concentration of at least 1.0 mole percent, wherein a least 1.0 mole percent of said hydrogen
sulfide in said acid gas exits said acid gas enrichment zone with said hydrogen sulfide depleted
off-gas.
21. The process of claim 19, wherein said hydrogen sulfide depleted off-gas
comprises hydrogen sulfide in an amount of at least 0.5 mole percent, wherein said acid gas
comprises carbonyl sulfide and one or more types of mercaptans in a combined concentration of
at least 0.025 mole percent.
22. The process of claim 21, wherein at least 80 mole percent of said carbonyl sulfide
and said mercaptans in said acid gas exit said acid gas enrichment zone with said hydrogen
sulfide depleted off-gas.
23. The process of claim 21, further comprising hydrogenating at least a portion of
said hydrogen sulfide depleted off-gas thereby converting at least a portion of said mercaptans
and/or said carbonyl sulfide in said hydrogen sulfide depleted off-gas to hydrogen sulfide.
24. The process of claim 23, further comprising, prior to said hydrogenating,
combining said hydrogen sulfide depleted off-gas with a Claus tail gas produced during a Claus
sulfur recovery process to thereby form a hydrogenation feed stream.
25. The process of claim 19, wherein said partially-loaded sulfur absorbing solvent
comprises hydrogen sulfide in an amount of 0.60 mole percent or less.
26. The process of claim 19, wherein said sulfur absorbing solvent comprises a
polyalkanol amine.
27. The process of claim 19, further comprising routing at least a portion of said
enriched hydrogen sulfide stream to a Claus sulfur recovery process, wherein said Claus sulfur
recovery process converts at least a portion of said hydrogen sulfide in said enriched hydrogen
sulfide stream into elemental sulfur thereby generating a sulfur rich stream and a Claus tail gas.
28. The process of claim 19, wherein the hydrogen sulfide content of said hydrogen
sulfide rich sulfur absorbing solvent is at least 3.0 mole percent.
29. A sulfur recovery system for recovering sulfur from an acid gas, said sulfur
recovery system comprising:
an acid gas enrichment absorber vessel containing a sulfur absorbing solvent operable for
removing hydrogen sulfide from said acid gas;
a sulfur absorbing solvent regenerator in downstream fluid communication with said acid
gas enrichment absorber vessel and operable for separating hydrogen sulfide from
said sulfur absorbing solvent and generating an enriched hydrogen sulfide stream
and a regenerated sulfur absorbing solvent;
a Claus sulfur recovery unit in downstream fluid communication with said sulfur
absorbing solvent regenerator and operable for recovering sulfur from said
enriched hydrogen sulfide stream;
a heater/mixer unit in downstream fluid communication with said Claus sulfur recovery
unit and said acid gas enrichment vessel and operable for mixing and heating a
tail gas from said Claus sulfur recovery unit and a hydrogen sulfide depleted offgas
from said acid gas enrichment absorber vessel;
a hydrogenation unit in downstream fluid communication with said heater/mixer unit
operable for hydrogenating a hydrogenation feed stream discharged from said
heater/mixer unit;
a quench column in downstream fluid communication with said hydrogenation unit; and
a tail gas treatment absorber vessel in downstream fluid communication with said quench
column and operable for removing hydrogen sulfide from a hydrogenated Claus
tail gas and acid gas enrichment off-gas.
30. The sulfur recovery system of claim 29, wherein said sulfur absorbing solvent
regenerator is in upstream fluid communication with said tail gas treatment absorber vessel and
operable to direct at least a portion of said regenerated sulfur absorbing solvent to said tail gas
treatment absorber vessel.
3 1. The sulfur recovery system of claim 29, wherein said sulfur recovery system is
operable to recover at least 99.5 weight percent of sulfur from said acid gas, wherein said acid
gas comprises at least 1 mole percent hydrogen sulfide and comprises carbonyl sulfide and one
or more types of mercaptans in a combined concentration of at least 0,025 mole percent.
32. The sulfur recovery system of claim 29, wherein said sulfur absorbing solvent
comprises a polyalkanol amine.
33. The sulfur recovery system of claim 29, wherein said acid gas enrichment
absorber vessel comprises a lower acid gas inlet and an upper sulfur absorbing solvent inlet,
wherein said acid gas enrichment absorber vessel comprises a packing material and/or a plurality
of contacting trays.
34. The sulfur recovery system of claim 29, wherein said quench column comprises a
lower gas inlet operable to receive a quench feed stream, wherein said quench column comprises
a packing material and/or a plurality of contacting trays to facilitate contact between said quench
feed stream and a water-containing stream.
35. The sulfur recovery system of claim 29, further comprising a waste heat boiler
interposed in fluid communication between said hydrogenation unit and said quench column.