Note: Descriptions are shown in the official language in which they were submitted.
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INTEGRATED ACID GAS AND SOUR GAS REINJECTION PROCESS
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional Application
60/633,361, filed 3 December, 2004.
BACKGROUND OF THE INVENTION
Field of the Invention
[0002] 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.
Description of the Related Art
[0003] 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.
[0004] 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.
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[0005] 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, Texas, vol. 4,
no. 3,
August 1989, pp. 265-271 (ISSN 0885-9221); E. R. Thomas et al., "Conceptual
Studies for CO2 /Natural Gas Separation Using the Controlled Freeze Zone (CFZ)
Process," Gas Separation & Purification, vol. 2 June 1988 pp. 84-89; U.S.
5,956,971
(Cole et al.); P. S. Northrop et al., "Cryogenic Sour Gas Process Attractive
for Acid
Gas Injection Applications," Proceedings Amlual Convention - Gas Processors
Association, 14 March 2004, pp. 1-8; and U.S. 2003/131726 (Thomas et al.).
SUMMARY OF THE INVENTION
[0006] 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.
[0007] 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-
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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.
[0009] 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.
[0009] Further, a method for producing natural gas is provided. In at least
one
embodiment, the metllod 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.
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BRIEF DESCRIPTION OF THE DRAWINGS
[0010] 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.
[0011] Figure 1 schematically depicts a process 100 for processing a portion
of a
hydrocarbon streain required for consumption as a fuel gas or sales gas or
both, and
reinjecting the remainder of the hydrocarbon stream.
[0012] Figure 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.
[0013] Figure 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 Figure 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
[0014] 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
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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.
[0015] 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.
[0016] 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.
[0017] The term "acid gas" means any one or more of carbon dioxide (C02),
hydrogen sulfide (H2S), carbon disulfide (CS2), carbonyl sulfide (COS),
mercaptans
(R-SH, where R is an alkyl group having one to 20 carbon atoms), sulfur
dioxide
(SO2), combinations thereof, mixtures thereof, and derivatives thereof.
[0018] 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
[0019] Specific embodiments shown in the drawings will now be described. It is
einphasized that the claims should not be read to be limited to aspects of the
drawings.
Figure 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
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110, such as a pressure vessel for example. The well stream 10 is preferably
separated at about 40 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.
[0020] 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
llydrocarbon 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.
[0021] 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,
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hexane, and aromatics, for example. Illustrative aromatics include, but are
not limited
to, benzene, toluene, ethylbenzene and xylene.
[0022] 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.
[0023] Although not shown in Figure 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
[0024] 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
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"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.
[0025] A preferred solvent will pllysically 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,
methyldietlianolamine (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.
[0026] 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. Patent No. 5,820,837.
[0027] 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 FlexsorbTM and Flexsorb
SETM
which are commercially available from Exxon Mobil Research and Engineering. An
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MDEA solvent as described above may also be used. Additional details can also
be
found in U.S. Patent No. 5,820,837.
CRYOGENIC DISTILLATION
[0028] 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 witli 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.
[0029] 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 C to about 10 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 C to about 0 C.
[0030] 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 US Patent No. 4,533,372
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CFZ (FIGURE 2)
[0031] Figure 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 US Patent 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,
downcomers,
weirs, packing, or any combination thereof.
[0032] 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 C to about 10 C. The
reboiler 215
can be controlled to leave less than about 5% by volume methane in the streain
50,
such as less than 4%, or less than 3%, or less than 2%, or less than 1%.
[0033] 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 coluinn 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.
[0034] 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
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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.
[0035] 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.
[0036] Referring again to Figure 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
fiuther, a
lower pressure disposal stream 50 may be vaporized and then compressed to a
higher
pressure.
[0037] 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.
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[0038] 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
1Ø 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.
[0039] In one or more embodiments, the combined stream 60 has a temperature of
greater than -20 C (-4 F). In one or more embodiments, the combined stream 60
has
a temperature of greater than 0 C (32 F). In one or more embodiments, the
combined
stream 60 has a temperature of greater than 10 C (50 F). In one or more
embodiments, the combined stream 60 has a temperature greater than 15.6 C (60
F),
21.1 C (70 F), or 26.7 C (80 F). In one or more embodiments, the combined
stream
60 has a temperature ranging from 21.1 C (70 F) to 54.4 C (130 F), or
alternatively
from 26.7 C (80 F) to 48.9 C (120 F).
[0040] The combined streain 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.
[0041] The molecular weiglit of the combined stream 60 may depend on the
concentration of the carbon dioxide and hydrogen sulfide in the streain. 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
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from about 5% by volume of hydrogen sulfide to about 40% by volume of hydrogen
sulfide.
[0042] 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.
[0043] 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.
[0044] 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
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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.
[0045] Figure 3 schematically depicts an alternative embodiment of the process
100 described with reference to Figure 1. In this process 300, the hydrocarbon
stream
is separated within at low temperature separation unit 310 to remove any
condensable liquids from the hydrocarbon streain 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
streain 12. The condensate stream 12 may then be sweetened, fractionated and
sold.
[0046] In one or more embodiments, the hydrocarbon stream 10 can be
deliydrated to remove water prior to the low temperature separation unit 310,
as
shown in Figure 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.
CA 02583120 2007-04-02
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Specific Embodiments of Claims
[0047] 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
streain
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 tliird 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.
[0048] 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 voluine of the carbon dioxide based on total volume of the second stream
and a
second stream having one or more liydrocarbons that includes four or more
carbon
atoms.
[0049] 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 coinprising 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 fourtli 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.
CA 02583120 2007-04-02
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16
[0050] 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.
[0051] 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.
