U.S. patent application number 11/664038 was filed with the patent office on 2008-02-14 for integrated acid gas and sour gas reinjection process.
Invention is credited to Eleanor R. Fieler, Edward J. Grave, P. Scott Northrop, Peter C. Rasmussen.
Application Number | 20080034789 11/664038 |
Document ID | / |
Family ID | 34956547 |
Filed Date | 2008-02-14 |
United States Patent
Application |
20080034789 |
Kind Code |
A1 |
Fieler; Eleanor R. ; et
al. |
February 14, 2008 |
Integrated Acid Gas And Sour Gas Reinjection Process
Abstract
A method for hydrocarbon processing is provided. In one or more
embodiments, the method includes splitting a hydrocarbon stream
comprising natural gas and acid gas into a first stream and a
second stream. Alternatively, the first stream and second stream
may be provided from other sources. The first stream is processed
to remove a portion of the acid gas therefrom, thereby producing a
third stream comprising the acid gas removed from the first stream
and a fourth stream comprising less than 100 ppm of
sulfur-containing compounds. The second stream is combined with the
third stream to provide a combined stream, which is compressed and
reinjected into a subterranean reservoir.
Inventors: |
Fieler; Eleanor R.; (Humble,
TX) ; Northrop; P. Scott; (Spring, TX) ;
Rasmussen; Peter C.; (Conroe, TX) ; Grave; Edward
J.; (Spring, TX) |
Correspondence
Address: |
Adam P. Brown;ExxonMobil Upstream Research Company
P.O.Box 2189
CORP-URC-SW348
Houston
TX
77252-2189
US
|
Family ID: |
34956547 |
Appl. No.: |
11/664038 |
Filed: |
October 19, 2005 |
PCT Filed: |
October 19, 2005 |
PCT NO: |
PCT/US05/38236 |
371 Date: |
March 28, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60633361 |
Dec 3, 2004 |
|
|
|
Current U.S.
Class: |
62/623 ; 62/620;
62/631 |
Current CPC
Class: |
F25J 2220/66 20130101;
F25J 3/0238 20130101; Y02C 10/12 20130101; F25J 2270/04 20130101;
F25J 2200/02 20130101; F25J 2205/20 20130101; F25J 2240/02
20130101; Y02C 20/40 20200801; F25J 2280/40 20130101; F25J 2240/30
20130101; F25J 2260/80 20130101; F25J 2200/76 20130101; F25J 3/0233
20130101; F25J 2210/06 20130101; C10L 3/10 20130101; F25J 3/0209
20130101; F25J 3/0266 20130101 |
Class at
Publication: |
062/623 ;
062/620; 062/631 |
International
Class: |
F25J 3/00 20060101
F25J003/00 |
Claims
1. A method for producing natural gas, comprising: providing a
first hydrocarbon stream comprising methane and acid gas and a
second hydrocarbon stream comprising methane and acid gas;
processing the first stream to remove a portion of the acid gas
therefrom, thereby producing a third stream comprising the acid gas
removed from the second stream and a fourth stream comprising less
than 100 ppm of sulfur-containing compounds; combining the second
stream with the third stream to provide a combined stream;
compressing the combined stream; and passing the combined stream to
a subterranean reservoir.
2. The method of claim 1, further comprising liquefying the fourth
stream to form a liquefied natural gas stream.
3. The method of claim 2, further comprising transporting the
liquefied natural gas stream from a first location to a second
location.
4. The method of claim 3, further comprising regasifying the
liquefied natural gas stream to a gaseous state.
5. The method of claim 1, wherein in the compressing step the
combined stream enters a compressor as a gas and discharges from
the compressor as a supercritical fluid.
6. A method for hydrocarbon processing, comprising: providing a
first stream comprising methane and acid gas and a second stream
comprising methane and acid gas; processing the first stream to
remove a portion of the acid gas therefrom, thereby producing a
third stream comprising the acid gas removed from the first stream
and a fourth stream comprising less than 100 ppm of
sulfur-containing compounds; combining the second stream with the
third stream to provide a combined stream; compressing the combined
stream; and passing the combined stream to a subterranean
reservoir.
7. The method of claim 6, wherein the first and second streams are
provided by splitting a feed stream into the first and second
streams.
8. The method of claim 6, wherein the first and second streams are
provided from two different sources.
9. The method of claim 6, further comprising mixing the combined
stream using a static mixer prior to passing the combined stream to
the subterranean reservoir.
10. The method of claim 6, further comprising mixing the combined
stream using an eductor prior to passing the combined stream to the
subterranean reservoir.
11. The method of claim 6, wherein the combined stream is
compressed to a pressure of about 250 bar or more.
12. The method of claim 6, wherein the combined stream is
compressed to a pressure of about 500 bar or more.
13. The method of claim 6, wherein in the compressing step the
combined stream is a supercritical fluid at compression discharge
conditions.
14. The method of claim 6, wherein in the compressing step the
combined stream enters a compressor as a gas and discharges from
the compressor as a supercritical fluid.
15. The method of claim 6, further comprising compressing the third
stream prior to combining the third stream with the second
stream.
16. The method of claim 6, further comprising removing water from
the hydrocarbon stream prior to splitting the hydrocarbon stream
into the first stream and the second stream.
17. The method of claim 6, further comprising removing water from
the second stream prior to combining with the third stream.
18. The method of claim 6, further comprising removing water from
the third stream prior to combining with the second stream.
19. The method of claim 6, wherein processing the first stream
comprises contacting the first stream with one or more amine
solvents.
20. The method of claim 6, wherein processing the first stream
comprises contacting the first stream with MDEA.
21. The method of claim 6, wherein processing the first stream
comprises treating the first stream using cryogenic
distillation.
22. The method of claim 6, wherein at least 10% by volume of the
hydrocarbon stream is split into the first stream.
23. The method of claim 6, wherein at least 50% by volume of the
hydrocarbon stream is split into the first stream.
24. The method of claim 6, wherein at least 20% by volume of the
hydrocarbon stream is split into the second stream.
25. The method of claim 6, wherein the fourth stream is an enriched
gas stream for fuel consumption.
26. The method of claim 7, wherein the split of the feed stream is
determined by the volume of the fourth stream that is needed for
sale, use, or both.
27. The method of claim 7, wherein the split of the feed stream is
determined by the volume of the second stream that is needed to
achieve the discharge pressure of 300 bars or more in the
compressing step.
28. The method of claim 6, wherein the third stream comprises
methane, nitrogen and helium.
29. The method of claim 6, wherein the fourth stream comprises
carbon dioxide, one or more sulfur-containing compounds, ethane,
and hydrocarbons having three or more carbon atoms.
30. A method for hydrocarbon reinjection, comprising: at least
partially separating a hydrocarbon stream comprising methane,
ethane, propane, carbon dioxide, water, one or more
sulfur-containing compounds, and of from 0.5% to 10% by volume of
one or more hydrocarbons having four or more carbon atoms at
conditions sufficient to produce a first stream comprising one or
more sulfur-containing compounds and at least 2% by volume of the
carbon dioxide based on the total volume of the second stream and a
second stream comprising one or more hydrocarbons having four or
more carbon atoms; treating the first stream in a distillation
column having a controlled freeze zone to produce a third stream
comprising methane, ethane, and propane, and a fourth stream
comprising carbon dioxide and one or more sulfur-containing
compounds; passing the second stream around the distillation column
and mixing the bypassed second stream with the fourth stream to
produce a combined stream; and passing the combined stream into a
subterranean reservoir.
31. The method of claim 30, wherein the at least partially
separating includes evaporating.
32. The method of claim 31, wherein the conditions occur at a
pressure at or above 30 bars.
33. The method of claim 31, wherein the conditions occur at a
temperature at or below -40.degree. C.
34. The method of claim 31, wherein treating the second stream
comprises distilling the second stream in the presence of a
refrigerant to produce the third stream comprising methane, ethane,
and propane, and the fourth stream comprising carbon dioxide and
one or more sulfur-containing compounds.
35. The method of claim 31, wherein the hydrocarbon stream
comprises of from about 2% by volume to about 65% by volume of
carbon dioxide.
36. The method of claim 31, further comprising compressing the
combined stream to a pressure of 700 bar or more prior to passing
the combined stream into the reservoir.
37. The method of claim 31, further comprising removing water from
the hydrocarbon stream prior to at least partially separating the
hydrocarbon stream.
38. The method of claim 31, further comprising removing water from
the hydrocarbon stream prior to at least partially separating the
hydrocarbon stream, wherein the water is removed by contacting the
hydrocarbon stream with a molecular sieve.
39. The method of claim 31, further comprising removing water from
the second stream prior to treating the second stream in the
distillation column having the controlled freeze zone.
40. The method of claim 31, further comprising removing water from
the second stream prior to treating the second stream in the
distillation column having the controlled freeze zone, wherein the
water is removed by contacting the second stream with a molecular
sieve.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application 60/633,361, filed 3 Dec. 2004.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] Embodiments of the present invention generally relate to
methods for injecting hydrocarbon streams and/or waste streams
derived from produced hydrocarbon streams into the subsurface, and
to hydrocarbon products derived from such methods.
[0004] 2. Description of the Related Art
[0005] Raw natural gas and condensate most often contain acidic
impurities including sulfur-containing compounds that must be
removed prior to use. A typical purification process separates the
sulfur-containing compounds from the hydrocarbon stream. The
separated sulfur compounds are then usually converted into
non-toxic, non-hazardous elemental sulfur. This elemental sulfur is
often shipped to sulfuric acid plants, or stored for later use.
[0006] Sulfur removal is often the most difficult in terms of both
recovery and cost due to increasingly stringent environmental
regulations and product specifications. Further, it is generally
not desirable to generate elemental sulfur since there is a glut of
sulfur in most markets. There is a need, therefore, for a cost
effective treatment process that requires less capital expenditure
and less operating expenditure for producing purified hydrocarbon
gas for consumption purposes without the hassles and associated
expense of separating and converting sulfur impurities into
elemental sulfur.
[0007] Additional information relating to the field of the
invention can be found in: R. C. Haut et al., "Development and
Application of the Controlled-Freeze-Zone Process," SPE Production
Engineering, The Society, Richardson, Tex., vol. 4, no.3, August
1989, pp. 265-271 (ISSN 0885-9221); E. R. Thomas et al.,
"Conceptual Studies for CO.sub.2/Natural Gas Separation Using the
Controlled Freeze Zone (CFZ) Process," Gas Separation &
Purification, vol. 2 June 1988 pp. 84-89; U.S. Pat. No. 5,956,971
(Cole et al.); P. S. Northrop et al., "Cryogenic Sour Gas Process
Attractive for Acid Gas Injection Applications," Proceedings Annual
Convention--Gas Processors Association, 14 Mar. 2004, pp. 1-8; and
U.S. 2003/131726 (Thomas et al.).
SUMMARY OF THE INVENTION
[0008] A method for hydrocarbon processing is provided. In one or
more embodiments, the method includes providing a first hydrocarbon
stream comprising methane and acid gas and a second hydrocarbon
stream comprising methane and acid gas. Alternatively the first and
second hydrocarbon streams are provided by splitting a feed stream
into the first and second hydrocarbon streams. Alternatively, the
first stream and second stream may be provided from other sources.
The first stream is processed to remove a portion of the acid gas
therefrom, thereby producing a third stream comprising the acid gas
removed from the first stream and a fourth stream comprising less
than 100 ppm of sulfur-containing compounds. The second stream is
combined with the third stream to provide a combined stream, which
is compressed and reinjected into a subterranean reservoir. In one
or more embodiments described above or elsewhere herein, the
combined stream is compressed to a discharge pressure of about 200
bar or more prior to reinjection.
[0009] An alternative embodiment of the invention includes a method
for producing natural gas. The method including providing a first
hydrocarbon stream comprising methane and acid gas and a second
hydrocarbon stream comprising methane and acid gas. Processing the
first stream to remove a portion of the acid gas therefrom, thereby
producing a third stream comprising the acid gas removed from the
second stream and a fourth stream comprising less than 100 ppm of
sulfur-containing compounds. Combining the second stream with the
third stream to provide a combined stream, compressing the combined
stream and passing the combined stream to a subterranean
reservoir.
[0010] In at least one other embodiment, the method includes at
least partially separating a hydrocarbon stream comprising methane,
ethane, propane, carbon dioxide, water, one or more
sulfur-containing compounds, and of from 0.5% to 10% by volume of
one or more hydrocarbons having four or more carbon atoms. The
hydrocarbon stream is at least partially separated at conditions
sufficient to produce a first stream comprising one or more
sulfur-containing compounds and at least 2% by volume of the carbon
dioxide based on the total volume of the second stream and a second
stream comprising one or more hydrocarbons having four or more
carbon atoms. The first stream is treated in a distillation column
having a controlled freeze zone (CFZ) to produce a third stream
containing methane and lighter compounds (e.g., nitrogen and
helium) and a fourth stream containing carbon dioxide, one or more
sulfur-containing compounds, ethane, and certain heavier
hydrocarbons. The second stream is bypassed around the distillation
column and mixed with the fourth stream to produce a combined
stream. The combined stream is then passed into a subterranean
reservoir.
[0011] Further, a method for producing natural gas is provided. In
at least one embodiment, the method includes providing a first
hydrocarbon stream comprising methane and acid gas and a second
hydrocarbon stream comprising methane and acid gas. The first
stream is processed to remove a portion of the acid gas therefrom,
thereby producing a third stream comprising the acid gas removed
from the second stream and a fourth stream comprising less than 100
ppm of sulfur-containing compounds. The second stream is combined
with the third stream to provide a combined stream that is
compressed and passed to a subterranean reservoir. The fourth
stream is liquefied to form a liquefied natural gas stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0013] FIG. 1 schematically depicts a process 100 for processing a
portion of a hydrocarbon stream required for consumption as a fuel
gas or sales gas or both, and reinjecting the remainder of the
hydrocarbon stream.
[0014] FIG. 2 is a schematic process flow diagram of an
illustrative distillation process 200 that utilizes a column 225
having a controlled freeze zone (CFZ) according to one embodiment
described herein.
[0015] FIG. 3 schematically depicts an alternative process 300 for
processing a portion of a hydrocarbon stream required for
consumption as a fuel gas or sales gas or both, and reinjecting the
remainder of the hydrocarbon stream. This process 300 is similar to
the process 100 of FIG. 1, but also provides a low temperature
separation unit 310 prior to the sour gas processing unit 125.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
Introduction and Definitions
[0016] A detailed description will now be provided. Each of the
appended claims defines a separate invention, which for
infringement purposes is recognized as including equivalents to the
various elements or limitations specified in the claims. Depending
on the context, all references below to the "invention" may in some
cases refer to certain specific embodiments only. In other cases it
will be recognized that references to the "invention" will refer to
subject matter recited in one or more, but not necessarily all, of
the claims. Each of the inventions will now be described in greater
detail below, including specific embodiments, versions and
examples, but the inventions are not limited to these embodiments,
versions or examples, which are included to enable a person having
ordinary skill in the art to make and use the inventions, when the
information in this patent is combined with available information
and technology.
[0017] Various terms as used herein are defined below. To the
extent a term used in a claim is not defined below, it should be
given the broadest definition persons in the pertinent art have
given that term as reflected in at least one printed publication or
issued patent.
[0018] The term "gas" is used interchangeably with "vapor," and
means a substance or mixture of substances in the gaseous state as
distinguished from the liquid or solid state.
[0019] The term "acid gas" means any one or more of carbon dioxide
(CO.sub.2), hydrogen sulfide (H.sub.2S), carbon disulfide
(CS.sub.2), carbonyl sulfide (COS), mercaptans (R--SH, where R is
an alkyl group having one to 20 carbon atoms), sulfur dioxide
(SO.sub.2), combinations thereof, mixtures thereof, and derivatives
thereof.
[0020] The term "sour gas" means a gas containing undesirable
quantities of acid gas, e.g., 55 parts-per-million by volume (ppmv)
or more, or 500 ppmv, or 5 percent by volume or more, or 15 percent
by volume or more, or 35 percent by volume or more.
Specific Embodiments In Drawings
[0021] Specific embodiments shown in the drawings will now be
described. It is emphasized that the claims should not be read to
be limited to aspects of the drawings. FIG. 1 schematically depicts
an exemplary process for processing a hydrocarbon stream according
to the embodiments described. In one or more embodiments, a well
stream 10 that contains one or any combination of natural gas, gas
condensate, and volatile oil, is cooled and separated into gas,
oil, and water phases using a separator 110, such as a pressure
vessel for example. The well stream 10 is preferably separated at
about 40.degree. C. or more and about 60 bar or more. The oil and
water phases are processed as needed. The gas phase is a
hydrocarbon feed stream 11 that is split into at least a first
portion or "first stream" 20 and a second portion or "second
stream" 30. As such, the first stream 20 and the second stream 30
have identical compositions. The first stream 20 is directed to a
gas processing unit 125 to remove acid gas, producing a product
stream 40 for fuel, or sales, or both, and a disposal stream 50.
The second stream 30 bypasses the gas processing unit 125 and is
combined with the disposal stream 50 to provide a combined stream
60. The combined stream 60 is compressed by the compressor 150 and
then reinjected or otherwise passed into a subterranean reservoir
175 for disposal, for use as a pressure maintenance fluid, or for
use as an enhanced oil recovery (EOR) agent.
[0022] The feed stream 11 can be any hydrocarbon-containing stream.
An illustrative feed stream 11 is a sour gas stream that originates
from one or more hydrocarbon production wells either on-shore or
off-shore or both. For example, the feed stream 11 can be a
combined stream from two or more different wells. An illustrative
feed stream 11 includes of from about 20% by volume to about 95% by
volume of methane. Preferably, the feed stream 11 includes of from
about 50% by volume to about 90% by volume of methane. In addition
to containing methane and one or more other hydrocarbons, an
illustrative feed stream 11 may include carbon dioxide, one or more
sulfur-containing compounds and other impurities. For example, the
feed stream 11 may include up to 15% by volume of one or more
sulfur-containing compounds and other impurities, of from about 2%
by volume to about 65% by volume of carbon dioxide, and of from
about 20% by volume to about 90% by volume of one or more
hydrocarbons. Common impurities in the feed stream 11 may include,
but are not limited to, water, oxygen, nitrogen, argon, and helium.
Illustrative sulfur-containing compounds may include, but are not
limited to, mercaptans, hydrogen sulfide, carbon disulfide,
disulfide oil, and carbonyl sulfide.
[0023] Of the one or more hydrocarbons, up to 10% by volume can be
carbon-containing compounds having at least four carbon atoms, such
as butane, pentane, hexane, and aromatics, for example.
Illustrative aromatics include, but are not limited to, benzene,
toluene, ethylbenzene and xylene.
[0024] In one or more embodiments, the split of the feed stream 11
is determined by the volume of gas that is needed for fuel gas
and/or sales gas. As such, the volume of gas that is needed for
fuel and/or sales is directed to the sour gas processing unit 125
as the first stream 20 and the balance of the feed stream 11 is
split into the second stream 30 and bypassed around the sour gas
processing unit 125. For example, at least 10% by volume of the
feed stream 11 is split into the first stream 20 and processed in
the sour gas processing unit 125 to produce fuel gas, sales gas, or
both. In one or more embodiments, at least 15%, 20%, 30%, 40%, or
50% of the feed stream 11 is split into the first stream 20 and
processed in the sour gas processing unit 125. In one or more
embodiments, of from about 10% by volume to about 50% by volume of
the separated feed stream 11 is split into the first stream 20. In
one or more embodiments, at least 15%, 20%, 30%, 40%, or 50% of the
feed stream 11 is split into the second stream 30. In one or more
embodiments, of from about 15% to about 50% of the feed stream 11
is split into the second stream 30. In one or more embodiments, of
from about 15% to about 30% of the feed stream 11 is split into the
second stream 30.
[0025] Although not shown in FIG. 1, the feed stream 11 can be
dehydrated to remove water prior to the gas processing unit 125.
Any technique for removing water from a gaseous stream can be used.
For example, the feed stream 11 can be dehydrated by passing the
feed stream 11 through a packed bed of molecular sieves. In one or
more embodiments, one or both of the individual split streams 20,
30 can be dehydrated in lieu of or in addition to dehydrating the
feed stream 11 as described above.
Gas Processing Unit 125
[0026] The gas processing unit 125 removes acid gas and other
impurities from the first stream 20. The acid gas and other
impurities may be removed from the first stream 20 using any
separation process known in the art. For example, the acid gas and
other impurities can be removed using a solvent extraction process.
The term "solvent extraction process" encompasses any process known
in the art for extracting acid gases using a solvent. For example,
the first stream 20 can be passed to a contactor and contacted with
a counter-current flow of solvent at a pressure ranging from a low
of 10 bar, 20 bar, or 30 bar to a high of 80 bar, 90 bar, or 100
bar. The contactor can be an absorber tower or column, such as a
bubble-tray tower having a plurality of horizontal trays spaced
throughout or contain a packing material for liquid vapor
contacting.
[0027] A preferred solvent will physically and/or chemically
absorb, chemisorb, or otherwise capture the acid gases from the
first stream 20 upon contact. Illustrative solvents include, but
are not limited to, alkanolamines, aromatic amines, diamines,
sterically hindered amines, mixtures thereof or derivatives
thereof. Specific amines include monoethanolamine (MEA),
diethanolamine (DEA), diglycolamine, methyldiethanolamine (MDEA;
with and without activator), di-isopropanolamine (DIPA),
triethanolamine (TEA), and dimethylaniline, for example. Other
suitable solvents may include, for example, polyethylene glycol
ethers and derivatives thereof, carbonates, sulfites, nitrites,
caustics, methanol, sulfolane, and N-methyl-2-pyrrolidone (NMP),
either alone or in combination with the amines listed above.
[0028] In operation, the first stream 20 flows upward through the
contactor while the lean solvent flows downward through the
contactor. This is also known as counter-current flow. The solvent
strips or otherwise removes the acid gas and other impurities from
the first stream 20, producing the product stream 40 for fuel, or
sales, or both. The solvent having the removed acid gas and other
impurities (i.e. "rich solvent") is then regenerated using
techniques well known in the art. Details of an illustrative
absorption process are described in U.S. Pat. No. 5,820,837.
[0029] A selective absorption process can also be used. A selective
absorption process may be used alone or in combination with the
solvent extraction process described above. Such selective
absorption techniques are well known in the art and are more
selective toward a particular chemical specie, such as hydrogen
sulfide for example. Illustrative selective absorbents include
Flexsorb.TM. and Flexsorb SE.TM. which are commercially available
from Exxon Mobil Research and Engineering. An MDEA solvent as
described above may also be used. Additional details can also be
found in U.S. Pat. No. 5,820,837.
Cryogenic Distillation
[0030] In one or more embodiments, the acid gas and other
impurities can be removed from the first stream 20 using a
cryogenic distillation process. The first stream 20 is fed to a
distillation column operated at a low temperature and refluxed with
a refrigerated overhead stream. The first stream 20 can be chilled
prior to the column using cross-exchange with other process
streams, external refrigeration streams, or adiabatic expansion,
such as expansion through a Joule-Thompson ("J-T") valve or an
expander, for example. A portion of the overhead stream is the
product stream 40 and a portion of the bottoms from the column is
recovered as the disposal stream 60. The amount of acid gas in the
overhead can be controlled through the design of the column, such
as the number of trays, operating temperature, operating pressure,
etc., and through modification of the reflux rate.
[0031] The temperature and pressure of the column are controlled so
that a solid phase is not formed at any location within the column.
In one or more embodiments, the pressure of the column is
preferably of from about 20 bar to about 50 bar, and the operating
temperature of the column is from about -100.degree. C. to about
10.degree. C. More preferably, the pressure of the column is of
from about 20 bar to about 35 bar, and the operating temperature of
the column is from about -50.degree. C. to about 0.degree. C.
[0032] Typically, the operating temperature and pressure of the
column depend on the concentration of the carbon dioxide in the
first stream 20. Preferably, the concentration of the carbon
dioxide in the first stream 20 is from about 2% by volume to about
10% by volume. For carbon dioxide concentrations of about 10% by
volume or more, a cryogenic distillation process having a
controlled freeze zone (CFZ) is preferred. Additional details of an
illustrative cryogenic distillation process is described in U.S.
Pat. No. 4,533,372.
CFZ (FIG. 2)
[0033] FIG. 2 is a schematic process flow diagram of an
illustrative distillation process 200 that utilizes a column 225
having a controlled freeze zone (CFZ) as shown and described in
U.S. Pat. Nos. 4,533,372; 4,923,493; 5,062,270; 5,120,338; and
5,956,971. The column 225 is separated into three distinct sections
including a lower distillation section 230, middle controlled
freezing zone 235, and an upper distillation section 240. The
second stream 20 is introduced into the lower distillation section
230. The second stream 20 can be chilled and/or expanded prior to
entering the column 225. Alternatively, a Joule-Thomson valve may
be used in place of the expander. The internals of the lower
section 230 can include trays, downcorners, weirs, packing, or any
combination thereof.
[0034] A liquid stream 210 that contains carbon dioxide exits the
bottom of the lower section 230 and a portion of the liquid stream
210 is heated in a reboiler 215. The liquid stream 210 contains the
acid gas and some of the ethane and heavier hydrocarbons from the
first stream 20. A portion of the liquid stream 210 returns to the
column 225 as reboiled vapor. The remainder of the liquid stream
210 leaves the process 200 as the bottoms product which is the
stream 50. The reboiler 215 typically operates in a temperature
range of from about -10.degree. C. to about 10.degree. C. The
reboiler 215 can be controlled to leave less than about 5% by
volume methane in the stream 50, such as less than 4%, or less than
3%, or less than 2%, or less than 1%.
[0035] The lighter vapors exit the lower section 230 via a chimney
tray 216, and contact a liquid spray from nozzles or spray jet
assemblies 220. The vapor then continues up through the upper
distillation section 240 and contacts reflux introduced to the
column 225 through line 218. The vapor exits the column 225 through
an overhead line 214. A portion of the vapor is returned to the top
of the column 225 as liquid reflux via a refrigeration loop 250.
The remainder of the vapor is removed from the process 200 as fuel
gas, sales gas or both in stream 40.
[0036] The overhead refrigeration loop 250 includes a cross
exchanger 255 for extracting cold energy from the vapor leaving the
column via line 214. The warmed vapor stream 257 from the exchanger
255 is compressed in compressor 270 and cooled in cooler 280. A
portion of the cooled vapor stream 282 is passed through the
exchanger 255 and is at least partially condensed to form stream
254. The at least partially condensed stream 254 is then expanded
in expander 255, and returned to the upper distillation section 240
of the column 225 via line 218.
[0037] The liquid in the upper distillation section 240 is
collected and withdrawn from the column 225 via line 262. The
liquid in line 262 may be accumulated in vessel 265 and returned to
the controlled freezing zone 235 via spray nozzles 220. The vapor
rising through the chimney tray 216 meets the spray emanating from
the nozzles 220. Here, the gaseous carbon dioxide of the rising
vapor contacts the sprayed cold liquid and freezes. The solid
carbon dioxide falls to the bottom of the controlled freezing zone
235 and collects on the chimney tray 216. A level of liquid
(possibly containing some melting solids) is maintained in the
bottom of the controlled freezing zone 235. The temperature can be
controlled by an external heater (not shown). The heater can be
electric or any other suitable and available heat source. The
liquid flows down from the bottom of controlled freezing zone 235
through exterior line 272 into the upper end of the bottom
distillation section 230.
[0038] Referring again to FIG. 1, the disposal stream 50 is
combined with the bypassed second stream 30 to form the combined
stream 60. In the event the disposal stream 50 has a lower pressure
than the second stream 30, the disposal stream 50 may be pumped to
a higher pressure and then vaporized using cross-exchange with
another process stream or other heating media. Further, a disposal
stream 50 may be pumped to a higher pressure and flashed into the
bypassed second stream 30. Still further, a lower pressure disposal
stream 50 may be vaporized and then compressed to a higher
pressure.
[0039] In one or more embodiments, the disposal stream 50 and the
bypassed second stream 30 are mixed. The two streams 30, 50 may be
mixed in a pressure vessel or static mixer (not shown).
Alternatively, the streams 30, 50 may be mixed within piping having
a sufficient length and geometry to sufficiently mix the
streams.
[0040] In one or more embodiments, the combined stream 60 is a high
molecular weight gas. For example, the combined stream 60 can have
a specific gravity of greater than 0.5. In one or more embodiments,
the combined stream 60 has a specific gravity of greater than 0.6,
greater than 0.7, or greater than 0.8. In one or more embodiments,
the combined stream 60 has a specific gravity of greater than 1.0.
In one or more embodiments, the combined stream 60 has a specific
gravity ranging from a low of 0.5, 0.55, or 0.60 to a high of 0.7,
0.8, or 1.2. In one or more embodiments, the combined stream 60 has
a specific gravity of from 0.5 to 1.0 or of from 0.5 to 0.8.
[0041] In one or more embodiments, the combined stream 60 has a
temperature of greater than -20.degree. C. (-4.degree. F.). In one
or more embodiments, the combined stream 60 has a temperature of
greater than 0.degree. C. (32.degree. F.). In one or more
embodiments, the combined stream 60 has a temperature of greater
than 10.degree. C. (50.degree. F.). In one or more embodiments, the
combined stream 60 has a temperature greater than 15.6.degree. C.
(60.degree. F.), 21.1.degree. C. (70.degree. F.), or 26.7.degree.
C. (80.degree. F.). In one or more embodiments, the combined stream
60 has a temperature ranging from 21.1.degree. C. (70.degree. F.)
to 54.4.degree. C. (130.degree. F.), or alternatively from
26.7.degree. C. (80.degree. F.) to 48.9.degree. C. (120.degree.
F.).
[0042] The combined stream 60 can have a pressure less than about
300 bar, such as about 200 bar or less, or 150 bar or less, or 100
bar or less, depending on the upstream process requirements.
Therefore, a compressor 150 is used to boost the pressure of the
combined stream 60 for injection into a higher pressure reservoir
175. In certain locations, the reservoir 175 may have a pressure at
or above 250 bars, such as 300 bars or more, 400 bars or more, or
500 bars or more, or 700 bars or more.
[0043] The molecular weight of the combined stream 60 may depend on
the concentration of the carbon dioxide and hydrogen sulfide in the
stream. In one or more embodiments, the combined stream 60 includes
up to 50% by volume of carbon dioxide. In one or more embodiments,
the combined stream 60 includes up to 50% by volume of hydrogen
sulfide. In one or more embodiments, the combined stream 60
includes of from about 5% by volume of carbon dioxide to about 40%
by volume of carbon dioxide. In one or more embodiments, the
combined stream 60 includes of from about 5% by volume of hydrogen
sulfide to about 40% by volume of hydrogen sulfide.
[0044] In some embodiments the combined stream includes greater
than 10% by volume of methane and/or ethane. In alternative
embodiments, the combined stream contains greater than 20%, 30%,
40% or 50% by volume of methane and/or ethane. In some embodiments
the combined stream includes greater than 10% by volume of methane.
In some embodiments, the combined stream contains greater than 20%,
30%, 40% or 50% by volume of methane.
[0045] Any compressor 150 capable of operating in acid gas service,
such as a reciprocating or centrifugal compressor for example, can
be used. Preferably, the compressor 150 is capable of operating in
acid gas service at high discharge pressure. As mentioned above,
the compressor 150 discharge pressure is greater than 250 bars,
such as 300 bars or more, 400 bars or more, or 500 bars or more, or
700 bars or more. In one or more embodiments, the compressor 150
discharge pressure ranges from a low of 250, 300, or 350 bars to a
high of 500, 600, or 700 bars. In one or more embodiments, the
compressor 150 discharge pressure is of from 300 bars to 700 bars.
In one or more embodiments, the compressor 150 discharge pressure
is of from 300 bars to 500 bars. In one or more embodiments, the
compressor 150 discharge pressure is of from 500 bars to 700
bars.
[0046] In one or more embodiments, the compressor 150 must be
capable of pressurizing a supercritical fluid. As mentioned above,
the combined stream 60 can have a high molecular weight. Such a
high molecular weight gas is a "gas" at the compressor 150 suction
conditions but can enter the supercritical phase at the discharge
pressures specified above. The term "supercritical phase" refers to
a dense fluid that is maintained above its critical temperature.
The critical temperature is the temperature above which the fluid
cannot be liquefied by increasing pressure. A supercritical fluid
is typically compressible, similar to a gas, but is more dense than
a gas, i.e. more similar to a liquid. Suitable compressors for
supercritical fluid service have specially engineered seals, rotor
dynamic characteristics, metallic components, and elastomeric
components. For example, the seals must be fully redundant to
ensure leak-free operation under all conditions. The rotor dynamics
have to be able to handle a high molecular weight gas approaching
the dense phase. The metallic components have to be shown to
withstand corrosive levels of hydrogen sulfide without cracking,
and the elastomeric components have to withstand high pressure
hydrogen sulfide and carbon dioxide without failure during
depressurization.
[0047] FIG. 3 schematically depicts an alternative embodiment of
the process 100 described with reference to FIG. 1. In this process
300, the hydrocarbon stream 10 is separated within at low
temperature separation unit 310 to remove any condensable liquids
from the hydrocarbon stream 10 prior to splitting the hydrocarbon
stream 10 into the first stream 20 and the second stream 30. For
example, the hydrocarbon stream 10 may be chilled within a cooler
or adiabatically expanded using an expansion device. Preferably,
the hydrocarbon stream 10 is cooled or expanded at conditions
sufficient to provide a condensate stream 12 containing ethane,
propane, butane, and less than 20% by volume of the acid gas from
the hydrocarbon stream 10. A suitable cooler includes a heat
exchanger using a cross-exchange with other process streams or an
external refrigeration stream. Suitable expansion devices include,
but are not limited to, a Joule-Thompson ("J-T") valve or turbo
expander. The chilled hydrocarbon stream 10 is then separated to
provide a gas stream 11 and condensate stream 12. The condensate
stream 12 may then be sweetened, fractionated and sold.
[0048] In one or more embodiments, the hydrocarbon stream 10 can be
dehydrated to remove water prior to the low temperature separation
unit 310, as shown in FIG. 3. Any technique for removing water from
a gaseous stream can be used. For example, the hydrocarbon stream
10 can be dehydrated by passing the stream 10 through a packed bed
320 of molecular sieves. Although not shown, the gas stream 11 can
be dehydrated in lieu of or in addition to dehydrating the
hydrocarbon stream 10 as described above. Further, one or both of
the individual split streams 20, 30 can be dehydrated in lieu of or
in addition to dehydrating the hydrocarbon stream 10 as described
above.
Specific Embodiments of Claims
[0049] Various specific embodiments are described below, at least
some of which are also recited in the claims. For example, at least
one specific embodiment is directed to a method for hydrocarbon
processing by splitting a hydrocarbon stream comprising methane and
acid gas into a first stream and a second stream. The first stream
is processed to remove a portion of the acid gas therefrom, thereby
producing a third stream consisting essentially of the acid gas
removed from the first stream and a fourth stream comprising less
than 100 ppm of sulfur-containing compounds. The second stream is
then combined with the third stream to provide a combined stream,
which is then compressed and passed to a subterranean reservoir.
The combined stream is compressed to a pressure of about 200 bar or
more prior to passing the combined stream to the subterranean
reservoir.
[0050] In one or more embodiments described above or elsewhere
herein, the hydrocarbon stream can be at least partially evaporated
at conditions sufficient to produce a first stream having one or
more sulfur-containing compounds and at least 2% by volume of the
carbon dioxide based on total volume of the second stream and a
second stream having one or more hydrocarbons that includes four or
more carbon atoms.
[0051] At least one other specific embodiment is directed to a
method for producing natural gas. In one or more embodiments, this
method provides a first hydrocarbon stream comprising methane and
acid gas and a second hydrocarbon stream comprising methane and
acid gas. The first stream is processed to remove a portion of the
acid gas therefrom, thereby producing the third stream comprising
the acid gas removed from the second stream and a fourth stream
comprising less than 100 ppm of sulfur-containing compounds. The
second stream is combined with the third stream to provide the
combined stream that is compressed and passed to a subterranean
reservoir as described. The fourth stream is condensed or liquefied
to form a liquefied natural gas stream. The liquefied natural gas
stream can be stored, transported or sold on site.
[0052] Certain composition features have been described using a set
of numerical upper limits and a set of numerical lower limits. It
should be appreciated that ranges from any lower limit to any upper
limit are contemplated unless otherwise indicated. Certain lower
limits, upper limits and ranges appear in one or more claims below.
All numerical values are "about" or "approximately" the indicated
value, and take into account experimental error and variations that
would be expected by a person having ordinary skill in the art.
Furthermore, all patents, test procedures, and other documents
cited in this application are fully incorporated by reference to
the extent such disclosure is not inconsistent with this
application and for all jurisdictions in which such incorporation
is permitted.
[0053] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *