U.S. patent application number 13/096788 was filed with the patent office on 2011-08-18 for enhanced natural gas liquid recovery process.
Invention is credited to Naomi Baker, Jhansi Garikipati, Eric Prim.
Application Number | 20110197629 13/096788 |
Document ID | / |
Family ID | 44368675 |
Filed Date | 2011-08-18 |
United States Patent
Application |
20110197629 |
Kind Code |
A1 |
Prim; Eric ; et al. |
August 18, 2011 |
Enhanced Natural Gas Liquid Recovery Process
Abstract
A method comprises receiving a hydrocarbon feed stream;
separating the hydrocarbon feed stream into a heavy hydrocarbon
rich stream and a recycle stream, wherein the recycle stream
comprises a gas selected from the group consisting of carbon
dioxide, nitrogen, air, and water; and separating the recycle
stream into a natural gas liquids (NGL) rich stream and a purified
recycle stream. A plurality of process equipment configured to
receive a hydrocarbon feed stream, separate the hydrocarbon feed
stream into a heavy hydrocarbon rich stream and a recycle stream
comprising at least one C.sub.3+ hydrocarbon and a gas selected
from the group consisting of carbon dioxide, nitrogen, air, and
water, and separate the recycle stream into a NGL rich stream and a
purified recycle stream.
Inventors: |
Prim; Eric; (Houston,
TX) ; Baker; Naomi; (The Woodlands, TX) ;
Garikipati; Jhansi; (Tomball, TX) |
Family ID: |
44368675 |
Appl. No.: |
13/096788 |
Filed: |
April 28, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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12122336 |
May 16, 2008 |
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13096788 |
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60938726 |
May 18, 2007 |
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Current U.S.
Class: |
62/618 |
Current CPC
Class: |
F25J 2215/02 20130101;
F25J 2220/68 20130101; F25J 3/0247 20130101; F25J 2200/02 20130101;
F25J 2260/80 20130101; Y02C 10/12 20130101; F25J 2220/66 20130101;
F25J 2210/62 20130101; F25J 3/0209 20130101; Y02C 20/40 20200801;
C07C 9/15 20130101; F25J 2290/10 20130101; F25J 2205/40 20130101;
C10L 3/104 20130101; C07C 7/04 20130101; F25J 3/0242 20130101; F25J
3/0233 20130101; F25J 2205/50 20130101; F25J 3/0266 20130101; F25J
2200/74 20130101 |
Class at
Publication: |
62/618 |
International
Class: |
F25J 3/08 20060101
F25J003/08 |
Claims
1. A method comprising: receiving a hydrocarbon feed stream;
separating the hydrocarbon feed stream into a heavy hydrocarbon
rich stream and a recycle stream, wherein the recycle stream
comprises a gas selected from the group consisting of carbon
dioxide, nitrogen, air, and water; and separating the recycle
stream into a natural gas liquids (NGL) rich stream and a purified
recycle stream.
2. The method of claim 1, further comprising injecting the purified
recycle stream into a subterranean formation.
3. The method of claim 1, further comprising: separating the
recycle stream into a vapor recycle stream and a liquid recycle
stream; and dehydrating the vapor recycle stream.
4. The method of claim 3, further comprising dehydrating the liquid
recycle stream.
5. The method of claim 1, further comprising: separating the
recycle stream into a vapor recycle stream and a liquid recycle
stream; and dehydrating the liquid recycle stream.
6. The method of claim 1, further comprising separating the recycle
stream into a vapor recycle stream and a liquid recycle stream,
wherein the vapor recycle stream and the liquid recycle stream are
fed to the separation of the recycle stream as separate
streams.
7. The method of claim 6, wherein separating the vapor recycle
stream and the liquid recycle stream comprises using a three-phase
separator.
8. The method of claim 1, further comprising dehydrating at least a
portion of the recycle stream prior to separating the recycle
stream into the NGL rich stream and the purified recycle
stream.
9. The method of claim 1, wherein separating the recycle stream
comprises: separating the recycle stream into the purified recycle
stream and a sour NGL rich stream; and sweetening the sour NGL rich
stream, thereby producing the NGL rich stream.
10. The method of claim 9, further comprising: cooling the sour NGL
rich stream prior to sweetening the sour NGL rich stream; and
throttling the sour NGL rich stream prior to sweetening the sour
NGL rich stream.
11. The method of claim 9, wherein the NGL rich stream comprises no
more than about 5 percent acid gases.
12. The method of claim 1, further comprising: separating the NGL
rich stream into a heavy NGL stream and a light NGL stream; and
mixing the heavy NGL stream with the heavy hydrocarbon rich
stream.
13. The method of claim 12, further comprising: separating the
recycle stream into a vapor recycle stream and a liquid recycle
stream, wherein the vapor recycle stream and the liquid recycle
stream are fed to the separation of the recycle stream as separate
streams; and dehydrating at least one of the vapor recycle stream
and the liquid recycle stream.
14. The method of claim 12, wherein the heavy hydrocarbon rich
stream has a Reid vapor pressure of less than 6 after being mixed
with at least a portion of the heavy NGL stream.
15. The method of claim 12, wherein the light NGL stream has an
energy content of between about 1,000 British thermal units per
cubit foot (Btu/ft.sup.3) and about 1,200 Btu/ft.sup.3.
16. The method of claim 12, wherein the light NGL stream has a
vapor pressure of less than about 250 pounds per square inch gauge
(psig) at a standard temperature.
17. The method of claim 12, further comprising: combining a second
NGL rich stream with the NGL rich stream prior to separating the
NGL rich stream; and separating the second NGL rich stream along
with the NGL rich stream to form the heavy NGL stream and the light
NGL stream.
18. A plurality of process equipment configured to: receive a
hydrocarbon feed stream; separate the hydrocarbon feed stream into
a heavy hydrocarbon rich stream and a recycle stream comprising at
least one C.sub.3+ hydrocarbon and a gas selected from the group
consisting of carbon dioxide, nitrogen, air, and water; and
separate the recycle stream into a natural gas liquid (NGL) rich
stream and a purified recycle stream.
19. The process equipment of claim 18, further configured to:
separate the NGL rich stream into a heavy NGL stream and a light
NGL stream; and mix at least a portion of the heavy NGL stream with
the heavy hydrocarbon rich stream.
20. The process equipment of claim 18, wherein the NGL rich stream
comprises less than about 70 percent of the C.sub.3+ hydrocarbons
from the recycle stream.
21. The process equipment of claim 18, wherein the NGL rich stream
comprises from about 10 percent to about 50 percent of the C.sub.3+
hydrocarbons from the recycle stream.
22. The process equipment of claim 18, wherein the process
equipment configured to separate the recycle stream into the NGL
rich stream and the purified recycle stream is configured to:
separate the recycle stream into a vapor recycle stream and a
liquid recycle stream; and separate the vapor recycle stream and
the liquid recycle stream into the NGL rich stream and the purified
recycle stream.
23. The process equipment of claim 22, wherein the recycle stream
is separated in a separator, and wherein the vapor recycle stream
and the liquid recycle stream enter the separator as separate
streams.
24. The process equipment of claim 19, wherein the heavy
hydrocarbon rich stream has a Reid vapor pressure of less than 6 at
a temperature of about 100.degree. F. after being mixed with the
heavy NGL stream.
25. The process equipment of claim 19, further configured to:
combine a second NGL rich stream with the NGL rich stream prior to
separating the NGL rich stream; and separate the second NGL rich
stream along with the NGL rich stream to form the heavy NGL stream
and the light NGL stream.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] The present application is a continuation-in-part of and
claims priority to U.S. patent application Ser. No. 12/122,336,
filed May 16, 2008 by Eric Prim, and entitled "Natural Gas Liquid
Recovery Process," which claims priority to U.S. Provisional Patent
Application Ser. No. 60/938,726, filed May 18, 2007 by Eric Prim,
and entitled "NGL Recovery Process," both of which are incorporated
herein by reference as if reproduced in their entirety.
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable.
REFERENCE TO A MICROFICHE APPENDIX
[0003] Not applicable.
BACKGROUND
[0004] Carbon dioxide (CO.sub.2) is a naturally occurring substance
in most hydrocarbon subterranean formations. Carbon dioxide also
may be used for recovering or extracting oil and hydrocarbons from
subterranean formations. One carbon dioxide based recovery process
involves injecting carbon dioxide into an injection well, and
recovering heavy hydrocarbons and perhaps some of the carbon
dioxide from at least one recovery well. Carbon dioxide reinjection
process also may produce natural gas liquids (NGLs).
SUMMARY
[0005] In one aspect, the disclosure includes a method comprising
receiving a hydrocarbon feed stream, separating the hydrocarbon
feed stream into a heavy hydrocarbon rich stream and a carbon
dioxide recycle stream, separating the carbon dioxide recycle
stream into a NGL rich stream and a purified carbon dioxide recycle
stream, and injecting the purified carbon dioxide recycle stream
into a subterranean formation.
[0006] In another aspect, the disclosure includes a plurality of
process equipment configured to implement a method comprising
receiving a recycle stream comprising at least one C.sub.3+
hydrocarbon and a gas selected from the group consisting of carbon
dioxide, nitrogen, air, and water, and separating the recycle
stream into a NGL rich stream and a purified recycle stream,
wherein the NGL rich stream comprises less than about 70 percent of
the C.sub.3+ hydrocarbons from the recycle stream.
[0007] In a third aspect, the disclosure includes a method
comprising selecting a first recovery rate for a NGL recovery
process, estimating the economics of the NGL recovery process based
on the first recovery rate, selecting a second recovery rate that
is different from the first recovery rate, estimating the economics
of the NGL recovery process based on the second recovery rate, and
selecting the first recovery rate for the NGL recovery process when
the estimate based on the first recovery rate is more desirable
than the estimate based on the second recovery rate.
[0008] In a fourth aspect, the disclosure includes a method
comprising receiving a hydrocarbon feed stream; separating the
hydrocarbon feed stream into a heavy hydrocarbon rich stream and a
recycle stream, wherein the recycle stream comprises a gas selected
from the group consisting of carbon dioxide, nitrogen, air, and
water; and separating the recycle stream into a NGL rich stream and
a purified recycle stream.
[0009] In a fifth aspect, the disclosure includes a plurality of
process equipment configured to receive a hydrocarbon feed stream;
separate the hydrocarbon feed stream into a heavy hydrocarbon rich
stream and a recycle stream comprising at least one C.sub.3+
hydrocarbon and a gas selected from the group consisting of carbon
dioxide, nitrogen, air, and water; and separate the recycle stream
into a NGL rich stream and a purified recycle stream.
BRIEF DESCRIPTION OF THE DRAWINGS
[0010] FIG. 1 is a process flow diagram for an embodiment of a
carbon dioxide reinjection process.
[0011] FIG. 2 is a schematic diagram of an embodiment of a NGL
recovery process.
[0012] FIG. 3 is a chart depicting an embodiment of the
relationship between the NGL recovery rate and the energy
requirement.
[0013] FIG. 4 is a schematic diagram of an embodiment of a NGL
upgrade process.
[0014] FIG. 5 is a process flow diagram for another embodiment of a
reinjection process.
[0015] FIG. 6 is a schematic diagram of another embodiment of a NGL
recovery process.
[0016] FIG. 7 is a flowchart of an embodiment of a NGL recovery
optimization method.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0017] It should be understood at the outset that although an
illustrative implementation of one or more embodiments are provided
below, the disclosed systems and/or methods may be implemented
using any number of techniques, whether currently known or in
existence. The disclosure should in no way be limited to the
illustrative implementations, drawings, and techniques illustrated
below, including the exemplary designs and implementations
illustrated and described herein, but may be modified within the
scope of the appended claims along with their full scope of
equivalents.
[0018] Disclosed herein is a NGL recovery process that may be
implemented as part of a carbon dioxide reinjection process to
recover NGLs from a carbon dioxide recycle stream. When
implementing a carbon dioxide reinjection process, the carbon
dioxide is typically injected downhole into an injection well and a
stream comprising hydrocarbons and carbon dioxide is generally
recovered from a recovery well. The carbon dioxide may be separated
from the heavy hydrocarbons and then recycled downhole, e.g., in
the reinjection well. In some cases, the carbon dioxide recycle
stream may comprise some NGLs, which may be recovered prior to
injecting the carbon dioxide recycle stream downhole. The NGL
recovery process may be optimized by weighing the NGL recovery rate
against the amount of energy expended on NGL recovery.
[0019] FIG. 1 illustrates an embodiment of a carbon dioxide
reinjection process 100. The carbon dioxide reinjection process 100
may receive hydrocarbons and carbon dioxide from a subterranean
hydrocarbon formation 114, separate heavy hydrocarbons and some of
the NGLs from the carbon dioxide, and inject the carbon dioxide
downhole. As shown in FIG. 1, additional process steps may be
included in the carbon dioxide reinjection process, such as
compressing the carbon dioxide, dehydrating the carbon dioxide,
and/or adding additional carbon dioxide to the carbon dioxide
recycle stream. The specific steps in the carbon dioxide
reinjection process 100 are explained in further detail below.
[0020] The carbon dioxide reinjection process 100 may receive a
hydrocarbon feed stream 152 from a subterranean hydrocarbon
formation 114. The hydrocarbon feed stream 152 may be obtained from
at least one recovery well as indicated by the upward arrow in FIG.
1, but also may be obtained from other types of wells. In addition,
the hydrocarbon feed stream 152 may be obtained from the
subterranean hydrocarbon formation 114 using any suitable method.
For example, if a suitable pressure differential exists between the
subterranean hydrocarbon formation 114 and the surface, the
hydrocarbon feed stream 152 may flow to the surface via the
pressure differential. Alternatively, surface and/or downhole pumps
may be used to draw the hydrocarbon feed stream 152 from the
subterranean hydrocarbon formation 114 to the surface.
[0021] Although the composition of the hydrocarbon feed stream 152
will vary from one location to another, the hydrocarbon feed stream
152 may comprise carbon dioxide, methane, ethane, NGLs, heavy
hydrocarbons, hydrogen sulfide (H.sub.2S), helium, nitrogen, water,
or combinations thereof. The term "hydrocarbon" may refer to any
compound comprising, consisting essentially of, or consisting of
carbon and hydrogen atoms. The term "natural gas" may refer to any
hydrocarbon that may exist in a gas phase under atmospheric or
downhole conditions, and includes methane and ethane, but also may
include diminishing amounts of C.sub.3-C.sub.8 hydrocarbons. The
term "natural gas liquids" or NGLs may refer to natural gases that
may be liquefied without refrigeration, and may include
C.sub.3-C.sub.8 hydrocarbons. Both natural gas and NGL are terms
known in the art and are used herein as such. In contrast, the term
"heavy hydrocarbons" may refer to any hydrocarbon that may exist in
a liquid phase under atmospheric or downhole conditions, and
generally includes liquid crude oil, which may comprise C.sub.9+
hydrocarbons, branched hydrocarbons, aromatic hydrocarbons, and
combinations thereof.
[0022] The hydrocarbon feed stream 152 may enter a separator 102.
The separator 102 may be any process equipment suitable for
separating at least one inlet stream into a plurality of effluent
streams having different compositions, states, temperatures, and/or
pressures. For example, the separator 102 may be a column having
trays, packing, or some other type of complex internal structure.
Examples of such columns include scrubbers, strippers, absorbers,
adsorbers, packed columns, and distillation columns having valve,
sieve, or other types of trays. Such columns may employ weirs,
downspouts, internal baffles, temperature control elements, and/or
pressure control elements. Such columns also may employ some
combination of reflux condensers and/or reboilers, including
intermediate stage condensers and reboilers. Alternatively, the
separator 102 may be a phase separator, which is a vessel that
separates an inlet stream into a substantially vapor stream and a
substantially liquid stream, such as a knock-out drum, flash drum,
reboiler, condenser, or other heat exchanger. Such vessels also may
have some internal baffles, temperature control elements, and/or
pressure control elements, but generally lack any trays or other
type of complex internal structure commonly found in columns. The
separator 102 also may be any other type of separator, such as a
membrane separator. In a specific embodiment, the separator 102 is
a knockout drum. Finally, the separator 102 may be any combination
of the aforementioned separators arranged in series, in parallel,
or combinations thereof.
[0023] The separator 102 may produce a heavy hydrocarbon stream 154
and a carbon dioxide recycle stream 156. The heavy hydrocarbon
stream 154 may comprise most of the heavy hydrocarbons from the
hydrocarbon feed stream 152. In embodiments, the heavy hydrocarbon
stream 154 may comprise at least about 90 percent, at least about
95 percent, at least about 99 percent, or substantially all of the
heavy hydrocarbons from the hydrocarbon feed stream 152. The heavy
hydrocarbon stream 154 may be sent to a pipeline for transportation
or a storage tank 104, where it is stored until being transported
to another location or being further processed. In contrast, the
carbon dioxide recycle stream 156 may comprise most of the carbon
dioxide from the hydrocarbon feed stream 152. In embodiments, the
carbon dioxide recycle stream 156 may comprise at least about 90
percent, at least about 95 percent, at least about 99 percent, or
substantially all of the carbon dioxide from the hydrocarbon feed
stream 152. Similarly, the carbon dioxide recycle stream 156 may
comprise at least about 80 percent, at least about 90 percent, at
least about 95 percent, or substantially all of the natural gas
from the hydrocarbon feed stream 152. All of the percentages
referred to herein are molar percentages until otherwise
specified.
[0024] The carbon dioxide recycle stream 156 may enter a compressor
106. The compressor 106 may be any process equipment suitable for
increasing the pressure, temperature, and/or density of an inlet
stream. The compressor 106 may be configured to compress a
substantially vapor phase inlet stream, a substantially liquid
phase inlet stream, or combinations thereof. As such, the term
"compressor" may include both compressors and pumps, which may be
driven by electrical, mechanical, hydraulic, or pneumatic means.
Specific examples of suitable compressors 106 include centrifugal,
axial, positive displacement, turbine, rotary, and reciprocating
compressors and pumps. In a specific embodiment, the compressor 106
is a turbine compressor. Finally, the compressor 106 may be any
combination of the aforementioned compressors arranged in series,
in parallel, or combinations thereof.
[0025] The compressor 106 may produce a compressed carbon dioxide
recycle stream 158. The compressed carbon dioxide recycle stream
158 may contain the same composition as the carbon dioxide recycle
stream 156, but at a higher energy level. The additional energy in
the compressed carbon dioxide recycle stream 158 may be obtained
from energy added to the compressor 106, e.g., the electrical,
mechanical, hydraulic, or pneumatic energy. In embodiments,
difference in energy levels between the compressed carbon dioxide
recycle stream 158 and the carbon dioxide recycle stream 156 is at
least about 50 percent, at least about 65 percent, or at least
about 80 percent of the energy added to the compressor 106.
[0026] The compressed carbon dioxide recycle stream 158 may enter a
dehydrator 108. The dehydrator 108 may remove some or substantially
all of the water from the compressed carbon dioxide recycle stream
158. The dehydrator 108 may be any suitable dehydrator, such as a
condenser, an absorber, or an adsorber. Specific examples of
suitable dehydrators 108 include refrigerators, molecular sieves,
liquid desiccants such as glycol, solid desiccants such as silica
gel or calcium chloride, and combinations thereof. The dehydrator
108 also may be any combination of the aforementioned dehydrators
arranged in series, in parallel, or combinations thereof. In a
specific embodiment, the dehydrator 108 is a glycol unit. Any water
accumulated within or exiting from the dehydrator 108 may be
stored, used for other processes, or discarded.
[0027] The dehydrator 108 may produce a dehydrated carbon dioxide
recycle stream 160. The dehydrated carbon dioxide recycle stream
160 may contain little water, e.g., liquid water or water vapor. In
embodiments, the dehydrated carbon dioxide recycle stream 160 may
comprise no more than about 5 percent, no more than about 3
percent, no more than about 1 percent, or be substantially free of
water.
[0028] The dehydrated carbon dioxide recycle stream 160 may enter a
NGL recovery process 110. The NGL recovery process 110 may separate
the dehydrated carbon dioxide recycle stream 160 into a NGL rich
stream 162 and a purified carbon dioxide recycle stream 164. The
NGL rich stream 162 may only comprise a portion of the total NGLs
from the dehydrated carbon dioxide recycle stream 160. For example,
the NGL rich stream 162 may comprise less than about 70 percent,
from about 10 percent to about 50 percent, or from about 20 percent
to about 35 percent of the NGLs from the dehydrated carbon dioxide
recycle stream 160. By taking a less aggressive cut of the NGLs
and/or disregarding the recovery of methane, ethane, and optionally
propane from the dehydrated carbon dioxide recycle stream 160, the
NGL recovery process 110 may produce a relatively high quality NGL
rich stream 162 with relatively little process equipment or energy.
A specific example of a suitable NGL recovery process 110 is shown
in FIG. 2 and described in further detail below.
[0029] As mentioned above, the NGL recovery process 110 may produce
a relatively high-quality NGL rich stream 162. Specifically, while
the NGL recovery process 110 recovers only a portion, e.g., about
20 to about 35 percent, of the NGLs in the dehydrated carbon
dioxide recycle stream 160, the resulting NGL rich stream 162 is
relatively lean with respect to methane and the acid gases. For
example, the NGL rich stream 162 may comprise most of the butane
and heavier components from the dehydrated carbon dioxide recycle
stream 160. For example, the NGL rich stream 162 may comprise at
least about 90 percent, at least about 95 percent, at least about
99 percent, or substantially all of the C.sub.4+ from the
dehydrated carbon dioxide recycle stream 160. In an embodiment, the
NGL rich stream 162 may comprise at least about 20 percent, at
least about 40 percent, at least about 60 percent, or at least
about 70 percent of the C.sub.3+ from the dehydrated carbon dioxide
recycle stream 160. In embodiments, the NGL rich stream 162 may
comprise no more than about 10 percent, no more than about 5
percent, no more than about 1 percent, or be substantially free of
ethane. Similarly, the NGL rich stream 162 may comprise no more
than about 5 percent, no more than about 3 percent, no more than
about 1 percent, or be substantially free of methane. Moreover, the
NGL rich stream 162 may comprise no more than about 5 percent, no
more than about 3 percent, no more than about 1 percent, or be
substantially free of acid gases, such as carbon dioxide or
hydrogen sulfide. It will be realized that the composition of the
NGL rich stream 162 may be dependent on the dehydrated carbon
dioxide recycle stream 160 composition. The examples provided below
show the composition of the NGL rich stream 162 for three different
dehydrated carbon dioxide recycle stream 160 compositions. The NGL
rich stream 162 may be sent to a pipeline for transportation or a
storage tank, where it is stored until being transported to another
location or being further processed.
[0030] In an embodiment, the NGL rich stream 162 optionally may be
processed in an NGL upgrade process 170. The NGL upgrade process
170 may produce a relatively heavy NGL stream 172 that may be
combined with the heavy hydrocarbon stream 154. When combined, the
heavy NGL stream 172 and the heavy hydrocarbon stream 154 may meet
or exceed the pipeline and/or transportation thresholds or
standards for a heavy hydrocarbon stream, as described in more
detail with respect to FIG. 4. A relatively light NGL stream 174
may be sent to a pipeline for transportation or a storage tank,
where it may be stored until transported to another location or
further processed, as described in more detail with respect to FIG.
4. A specific example of a suitable NGL upgrade process 170 is
shown in FIG. 5 and described in further detail below.
[0031] As mentioned above, the NGL recovery process 110 may produce
a purified carbon dioxide recycle stream 164. The purified carbon
dioxide recycle stream 164 may comprise most of the carbon dioxide
from the dehydrated carbon dioxide recycle stream 160, as well as
some other components such as methane, ethane, propane, butane,
nitrogen, and hydrogen sulfide. In embodiments, the purified carbon
dioxide recycle stream 164 may comprise at least about 90 percent,
at least about 95 percent, at least about 99 percent, or
substantially all of the carbon dioxide from the dehydrated carbon
dioxide recycle stream 160. In addition, the purified carbon
dioxide recycle stream 164 may comprise at least about 90 percent,
at least about 95 percent, at least about 99 percent, or
substantially all of the methane from the dehydrated carbon dioxide
recycle stream 160. As such, the purified carbon dioxide recycle
stream 164 may comprise at least about 65 percent, at least about
80 percent, at least about 90 percent, or at least about 95 percent
carbon dioxide. In embodiments, the purified carbon dioxide recycle
stream 164 may comprise no more than about 10 percent, no more than
about 5 percent, no more than about 1 percent, or be substantially
free of C.sub.3+. Similarly, the purified carbon dioxide recycle
stream 164 may comprise no more than about 20 percent, no more than
about 10 percent, no more than about 5 percent, or be substantially
free of C.sub.2+.
[0032] The purified carbon dioxide recycle stream 164 may enter a
compressor 112. The compressor 112 may comprise one or more
compressors, such as the compressor 106 described above. In a
specific embodiment, the compressor 112 is a turbine compressor.
The compressor 112 may compress the purified carbon dioxide recycle
stream 164, thereby producing a carbon dioxide injection stream
168. The carbon dioxide injection stream 168 may contain the same
composition as the purified carbon dioxide recycle stream 164, but
at a higher energy level. The additional energy in the carbon
dioxide injection stream 168 may be obtained from energy added to
the compressor 112, e.g., the electrical, mechanical, hydraulic, or
pneumatic energy. In some embodiments, the difference in energy
levels between the carbon dioxide injection stream 168 and the
purified carbon dioxide recycle stream 164 is at least about 50
percent, at least about 65 percent, or at least about 80 percent of
the energy added to the compressor 112.
[0033] In some embodiments, a makeup stream 166 may be combined
with either the purified carbon dioxide recycle stream 164 or the
carbon dioxide injection stream 168. Specifically, as the carbon
dioxide reinjection process 100 is operated, carbon dioxide and
other compounds will be lost, e.g., by replacing the hydrocarbons
in the subterranean hydrocarbon formation 114, by leakage into
inaccessible parts of the subterranean hydrocarbon formation 114,
and/or to other causes. Alternatively, it may be desirable to
increase the amount of carbon dioxide and other compounds injected
downhole. As such, the makeup stream 166 may be combined with
either the purified carbon dioxide recycle stream 164 and/or the
carbon dioxide injection stream 168, for example in the compressor
112. Alternatively or additionally, the makeup stream 166 may be
combined with the carbon dioxide recycle stream 156, the compressed
carbon dioxide recycle stream 158, the dehydrated carbon dioxide
recycle stream 160, or combinations thereof. The makeup stream 166
may comprise carbon dioxide, nitrogen, methane, ethane, air, water,
or any other suitable compound. In an embodiment, the makeup stream
166 comprises at least 75 percent, at least 85 percent, or at least
95 percent carbon dioxide, nitrogen, methane, air, water, or
combinations thereof. Finally, the carbon dioxide injection stream
168 may be sent to a carbon dioxide pipeline rather than being
immediately injected downhole. In such a case, the carbon dioxide
injection stream 168 may meet the carbon dioxide pipeline
specifications. One example of a carbon dioxide pipeline
specification is: at least about 95 percent carbon dioxide,
substantially free of free water, no more than about 30 pounds of
vapor-phase water per million cubic feet (mmcf) of product, no more
than about 20 parts per million (ppm) by weight of hydrogen
sulfide, no more than about 35 ppm by weight of total sulfur, a
temperature of no more than about 120.degree. F., no more than
about four percent nitrogen, no more than about five percent
hydrocarbons (wherein the hydrocarbons do not have a dew point
exceeding about -20.degree. F.), no more than about 10 ppm by
weight of oxygen, and more than about 0.3 gallons of glycol per
mmcf of product (wherein the glycol is not in the liquid state at
the pressure and temperature conditions of the pipeline).
[0034] FIG. 2 illustrates an embodiment of a NGL recovery process
200. The NGL recovery process 200 may recover some of the NGLs from
a carbon dioxide recycle stream described above. For example, the
NGL recovery process 200 may be implemented as part of the carbon
dioxide reinjection process 100, e.g., by separating the dehydrated
carbon dioxide recycle stream 160 into a NGL rich stream 162 and a
purified carbon dioxide recycle stream 164. Alternatively, the NGL
recovery process 200 may be implemented as a stand-alone process
for recovering NGLs from a hydrocarbon containing stream.
[0035] The NGL recovery process 200 may begin by cooling the
dehydrated carbon dioxide recycle stream 160 in a heat exchanger
202. The heat exchanger 202 may be any equipment suitable for
heating or cooling one stream using another stream. Generally, the
heat exchanger 202 is a relatively simple device that allows heat
to be exchanged between two fluids without the fluids directly
contacting each other. Examples of suitable heat exchangers 202
include shell and tube heat exchangers, double pipe heat
exchangers, plate fin heat exchangers, bayonet heat exchangers,
reboilers, condensers, evaporators, and air coolers. In the case of
air coolers, one of the fluids comprises atmospheric air, which may
be forced over tubes or coils using one or more fans. In a specific
embodiment, the heat exchanger 202 is a shell and tube heat
exchanger.
[0036] As shown in FIG. 2, the dehydrated carbon dioxide recycle
stream 160 may be cooled using the cooled, purified carbon dioxide
recycle stream 258. Specifically, the dehydrated carbon dioxide
recycle stream 160 is cooled to produce the cooled carbon dioxide
recycle stream 252, and the cooled, purified carbon dioxide recycle
stream 258 is heated to produce the purified carbon dioxide recycle
stream 164. The efficiency of the heat exchange process depends on
several factors, including the heat exchanger design, the
temperature, composition, and flowrate of the hot and cold streams,
and/or the amount of thermal energy lost in the heat exchange
process. In embodiments, the difference in energy levels between
the dehydrated carbon dioxide recycle stream 160 and the cooled
carbon dioxide recycle stream 252 is at least about 60 percent, at
least about 70 percent, at least about 80, or at least about 90
percent of the difference in energy levels between the cooled,
purified carbon dioxide recycle stream 258 and the purified carbon
dioxide recycle stream 164.
[0037] The cooled carbon dioxide recycle stream 252 then enters a
NGL stabilizer 204. The NGL stabilizer 204 may comprise a separator
206, a condenser 208, and a reboiler 210. The separator 206 may be
similar to any of the separators described herein, such as
separator 102. In a specific embodiment, the separator 206 is a
distillation column. The condenser 208 may receive an overhead 254
from the separator 206 and produce the cooled, purified carbon
dioxide recycle stream 258 and a reflux stream 256, which is
returned to the separator 206. The condenser 208 may be similar to
any of the heat exchangers described herein, such as heat exchanger
202. In a specific embodiment, the condenser 208 is a shell and
tube, kettle type condenser coupled to a refrigeration process, and
contains a reflux accumulator. As such, the condenser 208 may
remove some energy 282 from the reflux stream 256 and cooled,
purified carbon dioxide recycle stream 258, typically by
refrigeration. The cooled, purified carbon dioxide recycle stream
258 is substantially similar in composition to the purified carbon
dioxide recycle stream 164 described above. Similarly, the reboiler
210 may receive a bottoms stream 260 from the separator 206 and
produce a sour NGL rich stream 264 and a boil-up stream 262, which
is returned to the separator 206. The reboiler 210 may be like any
of the heat exchangers described herein, such as heat exchanger
202. In a specific embodiment, the reboiler 210 is a shell and tube
heat exchanger coupled to a hot oil heater. As such, the reboiler
210 adds some energy 284 to the boil-up stream 262 and the sour NGL
rich stream 264, typically by heating. The sour NGL rich stream 264
may be substantially similar in composition to the NGL rich stream
162, with the exception that the sour NGL rich stream 264 has some
additional acid gases, e.g., acid gases 270 described below.
[0038] The sour NGL rich stream 264 then may be cooled in another
heat exchanger 212. The heat exchanger 212 may be like any of the
heat exchangers described herein, such as heat exchanger 202. For
example, the heat exchanger 212 may be an air cooler as described
above. A cooled, sour NGL rich stream 266 may exit the heat
exchanger 212 and enter a throttling valve 214. The throttling
valve 214 may be an actual valve such as a gate valve, globe valve,
angle valve, ball valve, butterfly valve, needle valve, or any
other suitable valve, or may be a restriction in the piping such as
an orifice or a pipe coil, bend, or size reduction. The throttling
valve 214 may reduce the pressure, temperature, or both of the
cooled, sour NGL rich stream 266 and produce a low-pressure sour
NGL rich stream 268. The cooled, sour NGL rich stream 266 and the
low-pressure sour NGL rich stream 268 have substantially the same
composition as the sour NGL rich stream 264, albeit with lower
energy levels.
[0039] The low-pressure sour NGL rich stream 268 then may be
sweetened in a separator 216. The separator 216 may be similar to
any of the separators described herein, such as separators 102 or
206. In an embodiment, the separator 216 may be one or more packed
columns that use a sweetening process to remove acid gases from the
low-pressure sour NGL rich stream 268. Suitable sweetening
processes include amine solutions, physical solvents such as
SELEXOL or RECTISOL, mixed amine solution and physical solvents,
potassium carbonate solutions, direct oxidation, absorption,
adsorption using, e.g., molecular sieves, or membrane filtration.
The separator 216 may produce the NGL rich stream 162 described
above. In addition, any acid gases 270 accumulated within or
exiting from the separator 216 may be stored, used for other
processes, or suitably disposed of. Finally, while FIGS. 1 and 2
are described in the context of carbon dioxide reinjection, it will
be appreciated that the concepts described herein can be applied to
other reinjection processes, for example those using nitrogen, air,
or water.
[0040] FIG. 3 illustrates an embodiment of a chart 300 depicting
the relationship between the NGL recovery rate and the energy
expended to recover NGLs in the NGL recovery process. The NGL
recovery rate may be a percentage recovery, and may represent the
amount of C.sub.3+ in the carbon dioxide recycle stream that is
recovered in the NGL rich stream. The energy requirement may be
measured in joules (J) or in horsepower (hp), and may represent the
energy required to generate the condenser energy and reboiler
energy described above. If additional compressors are needed at any
point in the carbon dioxide reinjection process than would be
required in an otherwise similar carbon dioxide reinjection process
that lacks the NGL recovery process, then the energy required to
operate such compressors may be included in the energy requirement
shown in FIG. 3.
[0041] As shown by curve 302, the energy requirements may increase
about exponentially as the NGLs are recovered at higher rates. In
other words, substantially higher energy may be required to recover
the NGLs at incrementally higher rates. For example, recovering a
first amount 304 of from about 20 percent to about 35 percent of
C.sub.3+ may require substantially less energy than recovering a
second amount 306 of from about 40 percent to about 65 percent of
C.sub.3+. Moreover, recovering the second amount 306 of from about
40 percent to about 65 percent of C.sub.3+ may require
substantially less energy than recovering a third amount 308 of
from about 70 percent to about 90 percent of C.sub.3+. Such
significant reduction in energy requirements may be advantageous in
terms of process feasibility and cost, where relatively small
decreases in NGL recovery rates may require significantly less
energy and process equipment, yielding significantly better process
economics. Although the exact relationship of the curve 302 may
depend on numerous factors especially the price of C.sub.3+, in an
embodiment the economics of the NGL recovery process when the NGL
recovery rate is in the second amount 306 may be better than the
economics of the NGL recovery process when the NGL recovery rate is
in the third amount 308. Similarly, the economics of the NGL
recovery process when the NGL recovery rate is in the first amount
304 may be significantly better than the economics of the NGL
recovery process when the NGL recovery rate is in the second amount
306. Such a relationship is counterintuitive considering that in
many other processes, the process economics generally improve with
increased recovery rates.
[0042] FIG. 4 illustrates an embodiment of a NGL upgrade process
500. The NGL upgrade process 500 may separate a portion of the
heavier components of the NGL rich stream 162 for blending with the
heavy hydrocarbon stream 154. For example, the NGL upgrade process
500 may be used to produce a relatively heavy NGL stream 172 for
combining with the heavy hydrocarbon stream 154 and a relatively
light NGL stream 174 that may be sold and/or used as a NGL product.
In general, the heavy hydrocarbon stream 154 may sell for a higher
price than the NGL rich stream 162. By mixing at least a portion of
the NGL rich stream 162 with the heavy hydrocarbon stream 154, the
NGL upgrade process 500 may be used to improve the economics and/or
revenue from the NGL recovery process. As a result, the NGL upgrade
process 500 may be considered in the NGL recovery optimization
method 400 described in more detail below.
[0043] The NGL upgrade process 500 may begin by passing the NGL
rich stream 162 into an NGL upgrade unit 502. The NGL rich stream
162 may be in the liquid phase after passing through separator 216.
The NGL upgrade unit 502 may comprise a separator 506, and a
reboiler 510. While not illustrated in FIG. 4, some embodiments of
the NGL upgrade unit 502 also may comprise a condenser. The
separator 506 may be similar to any of the separators described
herein, such as separator 102. In a specific embodiment, the
separator 506 is a stripping column with a partial reboiler 510,
and the separator 506 may not comprise a condenser. The downcoming
liquid phase may be provided by the liquid NGL rich stream 162,
which may be introduced at or near the top of the separator 506. In
an embodiment, a condenser may be used to at least partially
condense overhead stream 524 to produce at least a portion of the
downcoming liquid in separator 506. For example, the condenser may
be similar to any of the heat exchangers described herein, such as
heat exchanger 202. The reboiler 510 may receive a bottoms stream
508 from the separator 506 and produce a heavy NGL stream 514 and a
boil-up stream 512, which is returned to the separator 506 to
provide the rising vapor phase within the separator 506. The
reboiler 510 may be like any of the heat exchangers described
herein, such as heat exchanger 202. In a specific embodiment, the
reboiler 510 is a shell and tube heat exchanger coupled to a hot
oil heater. As such, the reboiler 510 adds some energy 516 to the
boil-up stream 512 and the heavy NGL stream 514, typically by
heating. The heavy NGL stream 514 may be substantially similar in
composition to the heavy NGL stream 172.
[0044] The heavy NGL stream 514 then may be cooled in a heat
exchanger 518. The heat exchanger 518 may be any equipment suitable
for heating or cooling one stream using another stream. Generally,
the heat exchanger 518 is a relatively simple device that allows
heat to be exchanged between two fluids without the fluids directly
contacting each other (i.e., indirect heat exchange). In an
embodiment, heat integration that comprises using one or more
streams in the overall process to cool the heavy NGL stream 514,
and thereby heating the one or more streams, may be used with heat
exchanger 518. Examples of suitable heat exchangers 518 include
shell and tube heat exchangers, double pipe heat exchangers, plate
fin heat exchangers, bayonet heat exchangers, reboilers,
condensers, evaporators, and air coolers. In the case of air
coolers, one of the fluids comprise atmospheric air, which may be
forced over tubes or coils using one or more fans. In a specific
embodiment, the heat exchanger 518 is a shell and tube heat
exchanger with the heavy NGL stream 514 passing on one side of the
exchanger and a cooling fluid stream 522 passing on the other. The
cooled, heavy NGL stream 172 may have substantially the same
composition as the heavy NGL stream 514, albeit with lower energy
levels.
[0045] The overhead stream 524 from separator 506 may comprise at
least a portion of the lighter NGL components and may be cooled in
another heat exchanger 526. The heat exchanger 526 may be like any
of the heat exchangers described herein, such as heat exchanger
202. For example, the heat exchanger 526 may be an air cooler as
described above. The cooled, light NGL stream 174 may have
substantially the same composition as the overhead stream 524,
albeit with lower energy levels.
[0046] As shown in FIG. 4, one or more additional NGL input streams
530, 532 may be introduced into the NGL upgrade process 500
upstream of the NGL upgrade unit 502. The additional NGL input
streams 530, 532 may comprise NGL streams from any suitable source,
such as one or more additional recovery plants. The NGL input
streams 530, 532 may be transported to the NGL upgrade unit 502 by
any suitable means. For example, the NGL input streams 530, 532 may
be transported to the NGL upgrade unit 502 through a pipeline or by
truck. The additional NGL input streams 530, 532 may contain one or
more acid gases and/or other contaminants. Depending on their
compositions, the additional NGL input streams 530, 532 may be
introduced at various input locations in the NGL recovery process.
For example, an input location may comprise a point upstream of the
separator 216 for an NGL input stream 530 comprising acid gas
components at or above a threshold level (e.g., a pipeline or
storage threshold), thereby allowing for sweetening prior to being
introduced to the downstream processes. As another example, an
input location for an NGL input stream 532 that comprises acid gas
components below the threshold level may comprise a point
downstream of the separator 216, thereby reducing the energy use of
the overall recovery process. The use of one or more additional
input streams may allow an NGL upgrade process 500 to upgrade the
NGL streams from a plurality of NGL recovery processes. For
example, multiple NGL recovery processes and/or additional sources
of NGL rich streams may feed the NGL product to a NGL upgrade
process, thereby reducing the need to install an NGL upgrade
process at each source of an NGL stream.
[0047] In general, the NGL upgrade process may be used to separate
a relatively heavy NGL stream 172 for blending with the heavy
hydrocarbon stream 154. The composition and flowrate of the heavy
NGL stream 172 may vary depending on the composition and flowrate
of the heavy hydrocarbon stream 154. As discussed above, the heavy
hydrocarbon stream 154 may be sent to a pipeline for transportation
or a storage tank, where it is stored until being transported to
another location or being further processed. Each of the downstream
uses for the heavy hydrocarbon stream 154 may have one or more
thresholds and/or standards that the heavy hydrocarbon stream 154
must meet in order to be transported or further processed. For
example, pipelines may generally have standards setting thresholds
for fluids passing through the pipeline, such as thresholds on
vapor pressure (e.g., expressed as a Reid vapor pressure standard),
carbon dioxide content, acid gas content (e.g., hydrogen sulfide
content), and water content (e.g., a dew point standard). In an
embodiment, the fluid transported in the pipeline may have a Reid
vapor pressure of no more than about 20, no more than about 15, or
no more than about 10. Accordingly, the composition and the
flowrate of the heavy NGL stream 172 may be controlled so that the
heavy hydrocarbon stream 154 may meet the transportation and/or
further processing standards and/or threshold downstream of the
mixing point between the heavy hydrocarbon stream 154 and the heavy
NGL stream 172.
[0048] In an embodiment, the composition and/or flowrate of the
heavy NGL stream 172 and the light NGL stream 174 may be
controlled, at least in part, to allow the light NGL stream 174 to
satisfy one or more transportation thresholds. The light NGL stream
174 may be transported using a variety of transportation means
and/or methods including, but not limited to, a pipeline and a
tanker truck. Each transportation method may have one or more
thresholds that the light NGL stream 174 may need to satisfy prior
to being accepted for transportation. For example, a pipeline may
have a heating value standard of between about 1,000 British
thermal units per cubic foot (Btu/ft.sup.3) and about 1,200
Btu/ft.sup.3, or alternatively between about 1,050 Btu/ft.sup.3 and
about 1,100 Btu/ft.sup.3. In an embodiment, the light NGL stream
174 also may be subject to a dew point standard. As another
example, tanker truck transportation may have a vapor pressure
requirement that the light NGL stream 174 not exceed a vapor
pressure of about 250 pounds per square inch gauge (psig) at a
temperature of 100.degree. F. Based on the applicable thresholds,
the composition and the flowrate of the heavy NGL stream 172 and
the light NGL stream 174 may be controlled so that the light NGL
stream 174 may meet the transportation thresholds, allowing the
light NGL stream 174 to be transported for further use.
[0049] FIG. 5 illustrates another embodiment of a carbon dioxide
reinjection process 600. The process shown in FIG. 5 and the
process of FIG. 1 are similar, and those portions with similar
numbering are described in more detail with respect to FIG. 1
above. In the interest of brevity, only those portions that differ
from FIG. 1 will be discussed with respect to FIG. 5.
[0050] As can be seen in FIG. 5, the dehydration of the compressed
carbon dioxide recycle stream 158 may be integrated with the NGL
recovery/dehydration process 610. The compressed carbon dioxide
recycle stream 158 may enter a NGL recovery/dehydration process
610. In an embodiment, the NGL recovery/dehydration process 610 may
comprise a separator 102 that produces multiple streams and allow
one or more phases of the compressed carbon dioxide recycle stream
158 to be dehydrated without dehydrating the entirety of the
compressed carbon dioxide recycle stream 158. This may allow for a
reduction in the size of the dehydration unit and a reduction in
the operating expense associated with the dehydrator. Further, the
separate processing of the phases may allow the downstream
processing units to receive each phase at a different location,
which may further improve the process economics as described in
more detail below with respect to FIG. 7.
[0051] The compressed carbon dioxide recycle stream 158 may enter
the NGL recovery/dehydration process 610. The NGL
recovery/dehydration process 610 may dehydrate, process, and
separate the compressed carbon dioxide recycle stream 158 into a
NGL rich stream 162 and a purified carbon dioxide recycle stream
164. The NGL rich stream 162 may only comprise a portion of the
total NGLs from the dehydrated carbon dioxide recycle stream 160. A
specific example of a suitable NGL recovery/dehydration process 610
is shown in FIG. 6 and described in further detail below.
[0052] As mentioned above, the NGL recovery/dehydration process 610
may produce a relatively high-quality NGL rich stream 162. The NGL
rich stream 162 may have about the same composition as the NGL rich
stream 162 in FIG. 1. The NGL rich stream 162 may be sent to a
pipeline for transportation or a storage tank, where it is stored
until transported to another location or further processed. In an
embodiment, the NGL rich stream optionally may be processed in an
NGL upgrade process 170, as described in more detail above. The NGL
upgrade process 170 may produce a relatively heavy NGL stream 172
that may be combined with the heavy hydrocarbon stream 154. When
combined, the heavy NGL stream 172 and the heavy hydrocarbon stream
154 may meet or exceed the pipeline and/or transportation
properties for a heavy hydrocarbon stream. A relatively light NGL
stream 174 may be sent to a pipeline for transportation or a
storage tank 104, where it may be stored until being transported to
another location or being further processed. A specific example of
a suitable NGL upgrade process 170 is shown in FIG. 4 and described
in further detail above.
[0053] As mentioned above, the NGL recovery/dehydration process 610
may produce a purified carbon dioxide recycle stream 164. The
purified carbon dioxide recycle stream 164 may have about the same
composition as the purified carbon dioxide recycle stream 164 in
FIG. 1. The purified carbon dioxide recycle stream 164 may enter a
compressor 112. The compressor 112 may comprise one or more
compressors, such as the compressor 106 described above. In some
embodiments, a makeup stream 166 may be combined with either the
purified carbon dioxide recycle stream 164 or the carbon dioxide
injection stream 168. The resulting carbon dioxide injection stream
168 then may be injected into the subterranean hydrocarbon
formation 114 or sent to a carbon dioxide pipeline.
[0054] FIG. 6 illustrates an embodiment of a NGL
recovery/dehydration process 700. The NGL recovery/dehydration
process 700 may dehydrate and recover some of the NGLs from a
carbon dioxide recycle stream. For example, the NGL
recovery/dehydration process 700 may be implemented as part of the
carbon dioxide reinjection process 600, e.g., by separating the
dehydrated carbon dioxide recycle stream 160 into a NGL rich stream
162 and a purified carbon dioxide recycle stream 164.
[0055] The NGL recovery process 700 may begin by cooling the
compressed carbon dioxide recycle stream 158 in a heat exchanger
702. The heat exchanger 702 may be any equipment suitable for
heating or cooling one stream using another stream. Generally, the
heat exchanger 702 is a relatively simple device that allows heat
to be exchanged between two fluids without the fluids directly
contacting each other. Examples of suitable heat exchangers 702
include shell and tube heat exchangers, double pipe heat
exchangers, plate fin heat exchangers, bayonet heat exchangers,
reboilers, condensers, evaporators, and air coolers. In the case of
air coolers, one of the fluids comprises atmospheric air, which may
be forced over tubes or coils using one or more fans. In a specific
embodiment, the heat exchanger 702 is a shell and tube heat
exchanger.
[0056] As shown in FIG. 6, the compressed carbon dioxide recycle
stream 158 may be cooled using the cooled, purified carbon dioxide
recycle stream 758. Specifically, the compressed carbon dioxide
recycle stream 158 is cooled to produce the cooled carbon dioxide
recycle stream 752, and the cooled, purified carbon dioxide recycle
stream 758 is heated to produce the purified carbon dioxide recycle
stream 164. The efficiency of the heat exchange process depends on
several factors, including the heat exchanger design, the
temperature, composition, and flowrate of the hot and cold streams,
and/or the amount of thermal energy lost in the heat exchange
process. In embodiments, the difference in energy levels between
the compressed carbon dioxide recycle stream 158 and the cooled
carbon dioxide recycle stream 752 is at least about 60 percent, at
least about 70 percent, at least about 80, or at least about 90
percent of the difference in energy levels between the cooled,
purified carbon dioxide recycle stream 758 and the purified carbon
dioxide recycle stream 164.
[0057] The cooled carbon dioxide recycle stream 752 then enters a
separator 718. The separator 718 may be similar to any of the
separators described herein, such as separator 102. In a specific
embodiment, the separator 718 is a three phase separator, which is
a vessel that separates an inlet stream into three distinct phases
such as a substantially vapor stream, a substantially first liquid
stream (e.g., an organic liquid phase), and a substantially second
liquid stream (e.g., an aqueous liquid phase). The first liquid
stream may primarily comprise hydrocarbons and the second liquid
stream may primarily comprise an aqueous fluid so that the first
and second liquid streams are at least partially insoluble in each
other and form two separable liquid phases. A three-phase separator
may have some internal baffles and/or weirs, temperature control
elements, and/or pressure control elements, but generally lacks any
trays or other type of complex internal structure commonly found in
columns. In an embodiment, the separator 718 may separate the
cooled carbon dioxide recycle stream 752 into a vapor recycle
stream 724, a liquid recycle stream 728, and an aqueous fluid
stream 732. The aqueous fluid stream 732 exiting from the
dehydrator 722 may be stored, used for other processes, or
discarded. The aqueous fluid stream 732 may first be treated to
remove a portion of any hydrocarbons in the stream prior to
storage, further use or process, or being discarded.
[0058] The vapor recycle stream 724 optionally may enter a
dehydrator 720. The dehydrator 720 may remove some or substantially
all of the water from the vapor recycle stream 724. The dehydrator
720 may be any suitable dehydrator, such as a condenser, an
absorber, or an adsorber. Specific examples of suitable dehydrators
720 include refrigerators, molecular sieves, liquid desiccants such
as glycol, solid desiccants such as silica gel or calcium chloride,
and combinations thereof. The dehydrator 720 also may be any
combination of the aforementioned dehydrators 720 and 722 arranged
in series, in parallel, or combinations thereof. In a specific
embodiment, the dehydrator 720 is a glycol unit. Any water
accumulated within or exiting from the dehydrator 720 may be
stored, used for other processes, or discarded.
[0059] The dehydrator 720 may produce a dehydrated vapor recycle
stream 726. The dehydrated vapor recycle stream 726 may contain
little water, e.g., liquid water or water vapor. In embodiments,
the dehydrated vapor recycle stream 726 may comprise no more than
about 5 percent, no more than about 3 percent, no more than about 1
percent, or be substantially free of water.
[0060] The liquid recycle stream 728 from the separator 718
optionally may enter a dehydrator 722. The dehydrator 722 may
remove some or substantially all of the water from the liquid
recycle stream 728. The dehydrator 722 may be any suitable
dehydrator, such as a condenser, an absorber, or an adsorber.
Suitable liquid-liquid separators such as hydro-cyclones and heater
treaters also may be used. In an embodiment, the water in the
liquid recycle stream 728 may be in the form of hydrates (e.g.,
clathrate hydrates) and/or an emulsion. Suitable separators
utilizing physical solvents, chemical solvents, and or heat may be
used to break the hydrates and/or emulsion and separate the water
from the remaining liquid recycle stream 728 components. Specific
examples of suitable dehydrators 722 include hydro-cyclones, heater
treaters, molecular sieves, liquid desiccants such as glycol, solid
desiccants such as silica gel or calcium chloride, and combinations
thereof. The dehydrator 722 also may be any combination of the
aforementioned dehydrators 722 arranged in series, in parallel, or
combinations thereof. Any water accumulated within or exiting from
the dehydrator 722 may be stored, used for other processes, or
discarded.
[0061] The dehydrator 722 may produce a dehydrated liquid recycle
stream 730. The dehydrated liquid recycle stream 730 may contain
little water, e.g., liquid water or water vapor. In embodiments,
the dehydrated liquid recycle stream 730 may comprise no more than
about 5 percent, no more than about 3 percent, no more than about 1
percent, or be substantially free of water.
[0062] In an embodiment, only one of the dehydrators 720, 722 may
be used. For example, any water contained in the cooled carbon
dioxide recycle stream 752 may preferentially distribute to the
vapor recycle stream 724 or the liquid recycle stream 728. By only
using one separator 720, 722 on the stream containing the majority
of the water, the dehydration requirements may be reduced, thereby
reducing both the installation and operating costs associated with
operating the dehydration system. In an embodiment in which only
one dehydrator is used, the remaining stream may pass directly from
the separator 718 to the separator 706. In an embodiment, both
dehydrators 720, 722 may be used, and dehydrators 720, 722 may
comprise different types of dehydrators. For example, dehydrator
720 may comprise a gas dehydration system while dehydrator 722 may
comprise a unit designed to primarily perform a liquid-liquid phase
separation. In an embodiment, both dehydrators 720, 722 may be used
and the separator 718 may be used to perform a first stage
separation of any free water, thereby reducing the dehydration
requirements. In still another embodiment, neither dehydrator 720,
722 may be used and rather separator 718 may be sufficient for
removing any free water and thereby dehydrating the cooled carbon
dioxide recycle stream 752 along with performing a first stage
flash of the cooled carbon dioxide recycle stream 752 to allow the
stream to be introduced to the NGL fractionator 704 as separate
streams. In yet another embodiment, the vapor recycle stream 724
and the liquid recycle stream 728 may be combined and passed to a
single dehydrator.
[0063] The dehydrated vapor recycle stream 726 and the dehydrated
liquid recycle stream 730 then may enter a NGL fractionator 704 as
separate streams. In an embodiment, the dehydrated vapor recycle
stream 726 and the dehydrated liquid recycle stream 730 may be fed
to a separator 706 in the NGL fractionator 704 at separate input
locations. The ability to feed the dehydrated vapor recycle stream
726 and the dehydrated liquid recycle stream 730 at separate
locations in the separator 706 may aid in the separation of the
various components into the overhead stream 754 and the bottoms
stream 760. While the dehydrated vapor recycle stream 726 is
illustrated as entering the separator 706 above the dehydrated
liquid recycle stream 730, the dehydrated vapor recycle stream 726
may entering the separator 706 below the dehydrated liquid recycle
stream 730, or enter at or near the same tray and/or location. In
an embodiment, the dehydrated vapor recycle stream 726 and the
dehydrated liquid recycle stream 730 may be combined prior to
entering the NGL fractionator 704.
[0064] The NGL fractionator 704 may comprise a separator 706, a
condenser 708, and a reboiler 710. The separator 706 may be similar
to any of the separators described herein, such as separator 102.
In a specific embodiment, the separator 706 is a distillation
column. In an embodiment, dehydrated vapor recycle stream 726 may
be introduced onto the tray and/or inlet location (e.g., when
structured packing is used) with the closest matching vapor
composition in the distillation column. Similarly, the dehydrated
liquid recycle stream 730 may be introduced onto the tray and/or
inlet location with the closest matching liquid composition. Actual
compositional measurements and/or process models may be used to
match the dehydrated vapor recycle stream 726 and the dehydrated
liquid recycle stream 730 to the appropriate trays and/or inlet
location in the distillation column.
[0065] The condenser 708 may receive an overhead stream 754 from
the separator 706 and produce the cooled, purified carbon dioxide
recycle stream 758 and a reflux stream 756, which is returned to
the separator 706. The condenser 708 may be similar to any of the
heat exchangers described herein, such as heat exchanger 702. In a
specific embodiment, the condenser 708 is a shell and tube, kettle
type condenser coupled to a refrigeration process, and contains a
reflux accumulator. As such, the condenser 708 may remove some
energy 782 from the reflux stream 756 and cooled, purified carbon
dioxide recycle stream 758, typically by refrigeration. The cooled,
purified carbon dioxide recycle stream 758 is substantially similar
in composition to the purified carbon dioxide recycle stream 164
described above. Similarly, the reboiler 710 may receive a bottoms
stream 760 from the separator 706 and produce a sour NGL rich
stream 764 and a boil-up stream 762, which is returned to the
separator 706. The reboiler 710 may be like any of the heat
exchangers described herein, such as heat exchanger 702. In a
specific embodiment, the reboiler 710 is a shell and tube heat
exchanger coupled to a hot oil heater. As such, the reboiler 710
adds some energy 784 to the boil-up stream 762 and the sour NGL
rich stream 764, typically by heating. The sour NGL rich stream 764
may be substantially similar in composition to the NGL rich stream
162, with the exception that the sour NGL rich stream 764 has some
additional acid gases, e.g., acid gases 770 described below.
[0066] The sour NGL rich stream 764 then may be cooled in another
heat exchanger 712. The heat exchanger 712 may be like any of the
heat exchangers described herein, such as heat exchanger 702. For
example, the heat exchanger 712 may be an air cooler as described
above. A cooled, sour NGL rich stream 766 exits the heat exchanger
712 and enters a throttling valve 714. The throttling valve 714 may
be an actual valve such as a gate valve, globe valve, angle valve,
ball valve, butterfly valve, needle valve, or any other suitable
valve, or may be a restriction in the piping such as an orifice or
a pipe coil, bend, or size reduction. The throttling valve 714 may
reduce the pressure, temperature, or both of the cooled, sour NGL
rich stream 766 and produce a low-pressure sour NGL rich stream
768. The cooled, sour NGL rich stream 766 and the low-pressure sour
NGL rich stream 768 have substantially the same composition as the
sour NGL rich stream 764, albeit with lower energy levels.
[0067] The low-pressure sour NGL rich stream 768 then may be
sweetened in a separator 716. The separator 716 may be similar to
any of the separators described herein, such as separator 102. In
an embodiment, the separator 716 may be one or more packed columns
that use a sweetening process to remove acid gases 770 from the
low-pressure sour NGL rich stream 768. Suitable sweetening
processes include amine solutions, physical solvents such as
SELEXOL or RECTISOL, mixed amine solution and physical solvents,
potassium carbonate solutions, direct oxidation, absorption,
adsorption using, e.g., molecular sieves, or membrane filtration.
The separator 716 may produce the NGL rich stream 162 described
above. In addition, any acid gases 770 accumulated within or
exiting from the separator 716 may be stored, used for other
processes, or suitably disposed of. Finally, while FIGS. 5 and 6
are described in the context of carbon dioxide recovery and/or
reinjection, it will be appreciated that the concepts described
herein can be applied to other recovery and/or reinjection
processes, for example those using nitrogen, air, or water.
[0068] As referenced above, FIG. 7 illustrates an embodiment of a
NGL recovery optimization method 400. The NGL recovery optimization
method 400 may be used to determine an improved or optimal project
estimate for implementing the NGL recovery process and recovering
NGLs at a suitable rate. As such, the NGL recovery process may be
configured using appropriate equipment design based on the NGL
recovery rate. Specifically, the NGL recovery optimization method
400 may design or configure the equipment size, quantity, or both
based on an initial NGL recovery rate and required energy, and
hence estimate the project feasibility and cost. The method 400 may
upgrade or improve the project estimate by iteratively incrementing
the initial NGL recovery rate, re-estimating the project, and
comparing the two estimates.
[0069] At block 402, the method 400 may select an initial NGL
recovery rate. The initial NGL recovery rate may be relatively
small, such as no more than about 20 percent recovery, no more than
about 10 percent recovery, no more than about 5 percent recovery,
or no more than about 1 percent recovery. Choosing the initial NGL
recovery rate at a small percentage of the total NGL amount may
result in a relatively low project estimate that may be increased
gradually to reach improved estimates.
[0070] The method 400 then may proceed to block 404, where the
project equipment size may be determined based on the initial NGL
recovery rate. Specifically, the size of the equipment described in
the NGL recovery process and any additional compressors as
described above may be determined. In addition, the pressure and
temperature ratings and material compositions of such equipment may
be determined at block 404, if desired.
[0071] The method 400 then may proceed to block 406, where the
project may be estimated. Project estimation may comprise an
economic evaluation of the NGL recovery process, and may include
the cost of obtaining, fabricating, and/or field constructing the
equipment sized in block 404. In addition, project estimation may
include the cost of operating and maintaining the NGL process, as
well as the revenue generated by the sale or use of the products
obtained by implementing the NGL process. As such, the project
estimate may comprise the total project benefits (including
production, sales, etc.) minus the total project capital and
operating costs (including cost, equipment, etc.). In some
embodiments, the project estimate may be based on an existing
carbon dioxide reinjection plant that lacks the NGL recovery
process.
[0072] The method 400 then may proceed to block 408, where the
recovery rate is incremented. The NGL recovery rate may be
incremented by a relatively small percentage, for example no more
than about 10 percent, not more than about 5 percent, or no more
than about 1 percent. The method 400 then may proceed to block 410,
which is substantially similar to block 404. The method 400 then
may proceed to block 412, which is substantially similar to block
406.
[0073] The method 400 then may proceed to block 414, where the
method 400 may determine whether the project estimate has improved.
For instance, the method 400 may compare the project estimate from
block 412 with the previous project estimate (either block 406 or
the previous iteration of block 412) and determine whether the
revised estimate is more economically desirable. The method 400 may
return to block 408 when the condition at block 414 is met.
Otherwise, the method 400 may proceed to block 416.
[0074] At block 416, the method 400 may choose the previous project
estimate as the final estimate. For example, the method 400 may
select the previous NGL recovery rate (either block 406 or the
previous iteration of block 412) instead of the estimate obtained
at block 412. In some embodiments, the desired or optimum recovery
rate selected at block 416 may represent a range of desirable or
optimum points, as opposed to a single point. Accordingly, the
method 400 may select the equipment sizing corresponding to the
selected NGL recovery rate. The selected project estimate and
sizing then may be used for the NGL recovery process. Of course, it
will be appreciated that the method 400 may be revised to include a
decremented, top-down estimation approach as opposed to an
incremented, bottom-up estimation approach.
[0075] The method 400 may have several advantages over other
project estimation methods. For example, process equipment of a
specific size may be selected, and the corresponding recovery rate
determined. Alternatively, a required recovery rate may be
selected, and the equipment sized to achieve the recovery rate.
However, it has been discovered that such approaches are inflexible
and often yields suboptimal process economics. For example,
relatively high NGL recovery rates will not lead to an improvement
in process economics, e.g., because of the exponential increase in
energy consumption. In contrast, the method 400 provides a flexible
approach to determining a desirable or optimal project
estimate.
[0076] In an embodiment, the equipment size may be configured to
allow for variations in recovery rates to accommodate changes in
economic conditions, such as C.sub.3+ or energy pricing.
Specifically, the equipment described herein can be sized above or
below the desired or optimum amount to allow the processes
described herein to operate at recovery rates slightly greater than
or slightly less than the desirable or optimum point obtained in
method 400. As the process parameters and the energy requirements
may be closely related, the ability of the process to continue to
successfully operate under differing conditions may be reflected by
constrained changes in the energy requirements of the process. When
operating in the first amount 304 or the second amount 306 on the
curve 302 in FIG. 3, significant increases or decreases in NGL
recovery rate may be obtained with little change in the energy
requirements. Such is not the case when operating in the third
amount 308 on the curve 302 in FIG. 3, where significant increases
or decreases in energy requirements yield only incremental changes
in NGL recovery rate.
Example 1
[0077] In one example, a process simulation was performed using the
NGL recovery process 200 shown in FIG. 2. The simulation was
performed using the Hyprotech Ltd. HYSYS Process v2.1.1 (Build
3198) software package. The NGL recovery process 200 separated the
dehydrated carbon dioxide recycle stream 160 into the purified
carbon dioxide recycle stream 164, the NGL rich stream 162, and the
acid gas stream 270. The specified values are indicated by an
asterisk (*). The physical properties are provided in degrees
Fahrenheit (F), psig, million standard cubic feet per day (MMSCFD),
pounds per hour (lb/hr), U.S. gallons per minute (USGPM), and
British thermal units per hour (Btu/hr). The material streams,
their compositions, and the associated energy streams produced by
the simulation are provided in tables 1, 2, and 3 below,
respectively.
TABLE-US-00001 TABLE 1 Material Streams Cooled, Dehydrated Cooled
CO.sub.2 Purified CO.sub.2 CO.sub.2 Recycle Recycle Recycle Name
Stream 160 Stream 252 Stream 258 Vapor Fraction 0.9838 0.9392
1.0000 Temperature (F.) 104.0* 45.00* 4.011 Pressure (psig) 340.0*
335.0 330.0 Molar Flow (MMSCFD) 17.00* 17.00 15.88 Mass Flow
(lb/hr) 8.049e+04 8.049e+04 7.254e+04 Liquid Volume Flow 218.1
218.1 192.3 (USGPM) Heat Flow (Btu/hr) -2.639e+08 -2.658e+08
-2.577e+08 Purified CO.sub.2 Sour NGL Cooled Sour Recycle Rich
Stream NGL Rich Name Stream 164 264 Stream 266 Vapor Fraction
1.0000 0.00000 0.0000 Temperature (F.) 97.39 202.6 120.0* Pressure
(psig) 325.0 340.0 635.3* Molar Flow (MMSCFD) 15.88 1.119 1.119
Mass Flow (lb/hr) 7.254e+04 7947 7947 Liquid Volume Flow 192.3
25.84 25.84 (USGPM) Heat Flow (Btu/hr) -2.558e+08 -8.443e+06
-8.862e+06 Low-Pressure Sour NGL Rich Stream Acid Gas NGL Rich Name
268 Stream 270 Stream 162 Vapor Fraction 0.0000 1.0000 0.0000
Temperature (F.) 120.9 100.0* 111.8 Pressure (psig) 200.3* 5.304*
185.3* Molar Flow (MMSCFD) 1.119 0.1030 1.016 Mass Flow (lb/hr)
7947 446.4 7501 Liquid Volume Flow 25.84 1.100 24.74 (USGPM) Heat
Flow (Btu/hr) -8.862e+06 -1.083e+06 -7.779e+06
TABLE-US-00002 TABLE 2 Stream Compositions Cooled, Dehydrated
Cooled CO.sub.2 Purified CO.sub.2 CO.sub.2 Recycle Recycle Recycle
Name Stream 160 Stream 252 Stream 258 Comp Mole Frac (H.sub.2S)
0.0333* 0.0333 0.0327 Comp Mole Frac (Nitrogen) 0.0054* 0.0054
0.0058 Comp Mole Frac (CO.sub.2) 0.7842* 0.7842 0.8359 Comp Mole
Frac (Methane) 0.0521* 0.0521 0.0558 Comp Mole Frac (Ethane)
0.0343* 0.0343 0.0348 Comp Mole Frac (Propane) 0.0406* 0.0406
0.0313 Comp Mole Frac (i-Butane) 0.0072* 0.0072 0.0022 Comp Mole
Frac (n-Butane) 0.0171* 0.0171 0.0015 Comp Mole Frac (i-Pentane)
0.0058* 0.0058 0.0000 Comp Mole Frac (n-Pentane) 0.0057* 0.0057
0.0000 Comp Mole Frac (n-Hexane) 0.0070* 0.0070 0.0000 Comp Mole
Frac (n-Octane) 0.0071* 0.0071 0.0000 Comp Mole Frac (H.sub.2O)
0.0000* 0.0000 0.0000 Purified CO.sub.2 Sour NGL Cooled Sour
Recycle Rich Stream NGL Rich Name Stream 164 264 Stream 266 Comp
Mole Frac (H.sub.2S) 0.0327 0.0421 0.0421 Comp Mole Frac (Nitrogen)
0.0058 0.0000 0.0000 Comp Mole Frac (CO.sub.2) 0.8359 0.0500 0.0500
Comp Mole Frac (Methane) 0.0558 0.0000 0.0000 Comp Mole Frac
(Ethane) 0.0348 0.0281 0.0281 Comp Mole Frac (Propane) 0.0313
0.1728 0.1728 Comp Mole Frac (i-Butane) 0.0022 0.0789 0.0789 Comp
Mole Frac (n-Butane) 0.0015 0.2388 0.2388 Comp Mole Frac
(i-Pentane) 0.0000 0.0887 0.0887 Comp Mole Frac (n-Pentane) 0.0000
0.0866 0.0866 Comp Mole Frac (n-Hexane) 0.0000 0.1063 0.1063 Comp
Mole Frac (n-Octane) 0.0000 0.1077 0.1077 Comp Mole Frac (H.sub.2O)
0.0000 0.0000 0.0000 Low- Pressure Sour NGL Rich Acid Gas NGL Rich
Name Stream 268 Stream 270 Stream 162 Comp Mole Frac (H.sub.2S)
0.0421 0.4568 0.0000 Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO.sub.2) 0.0500 0.5432 0.0000 Comp Mole Frac
(Methane) 0.0000 0.0000 0.0000 Comp Mole Frac (Ethane) 0.0281
0.0000 0.0309 Comp Mole Frac (Propane) 0.1728 0.0000 0.1903 Comp
Mole Frac (i-Butane) 0.0789 0.0000 0.0869 Comp Mole Frac (n-Butane)
0.2388 0.0000 0.2630 Comp Mole Frac (i-Pentane) 0.0887 0.0000
0.0977 Comp Mole Frac (n-Pentane) 0.0866 0.0000 0.0954 Comp Mole
Frac (n-Hexane) 0.1063 0.0000 0.1171 Comp Mole Frac (n-Octane)
0.1077 0.0000 0.1186 Comp Mole Frac (H.sub.2O) 0.0000 0.0000
0.0000
TABLE-US-00003 TABLE 3 Energy Streams Name Heat Flow (Btu/hr)
Condenser Q Energy Stream 282 1.469e+06 Reboiler Q Energy Stream
284 1.152e+06
Example 2
[0078] In another example, the process simulation was repeated
using a different dehydrated carbon dioxide recycle stream 160. The
material streams, their compositions, and the associated energy
streams produced by the simulation are provided in tables 4, 5, and
6 below, respectively.
TABLE-US-00004 TABLE 4 Material Streams Cooled, Dehydrated Cooled
CO.sub.2 Purified CO.sub.2 CO.sub.2 Recycle Recycle Recycle Name
Stream 160 Stream 252 Stream 258 Vapor Fraction 0.9874 0.9286
1.0000 Temperature (F.) 104.0* 60.00* 22.77 Pressure (psig) 685.3*
680.3 590.0 Molar Flow 20.00* 20.00 18.86 (MMSCFD) Mass Flow
(lb/hr) 8.535e+04 8.535e+04 7.780e+04 Liquid Volume Flow 258.0
258.0 232.2 (USGPM) Heat Flow (Btu/hr) -2.741e+08 -2.760e+08
-2.683e+08 Purified CO.sub.2 Sour NGL Cooled Sour Recycle Rich
Stream NGL Rich Name Stream 164 264 Stream 266 Vapor Fraction
1.0000 0.00000 0.0000 Temperature (F.) 87.48 290.7 120.0* Pressure
(psig) 585.0 600.0 635.3* Molar Flow 18.86 1.139 1.139 (MMSCFD)
Mass Flow (lb/hr) 7.780e+04 7552 7552 Liquid Volume Flow 232.2
25.83 25.83 (USGPM) Heat Flow (Btu/hr) -2.663e+08 -7.411e+06
-8.371e+06 Low-Pressure Sour NGL Rich Stream Acid Gas NGL Rich Name
268 Stream 270 Stream 162 Vapor Fraction 0.0000 1.0000 0.0000
Temperature (F.) 120.5 100.0* 118.6 Pressure (psig) 200.3* 5.304*
185.3* Molar Flow 1.139 0.02943 1.110 (MMSCFD) Mass Flow (lb/hr)
7552 141.2 7411 Liquid Volume Flow 25.83 0.3421 25.49 (USGPM) Heat
Flow (Btu/hr) -8.371e+06 -5.301e+05 -7.841e+06
TABLE-US-00005 TABLE 5 Stream Compositions Cooled, Dehydrated
Cooled CO.sub.2 Purified CO.sub.2 CO.sub.2 Recycle Recycle Recycle
Name Stream 160 Stream 252 Stream 258 Comp Mole Frac (H.sub.2S)
0.0004* 0.0004 0.0004 Comp Mole Frac (Nitrogen) 0.0153* 0.0153
0.0162 Comp Mole Frac (CO.sub.2) 0.6592* 0.6592 0.6975 Comp Mole
Frac (Methane) 0.1813* 0.1813 0.1922 Comp Mole Frac (Ethane)
0.0620* 0.0620 0.0620 Comp Mole Frac (Propane) 0.0411* 0.0411
0.0275 Comp Mole Frac (i-Butane) 0.0064* 0.0064 0.0017 Comp Mole
Frac (n-Butane) 0.0179* 0.0179 0.0024 Comp Mole Frac (i-Pentane)
0.0040* 0.0040 0.0000 Comp Mole Frac (n-Pentane) 0.0049* 0.0049
0.0000 Comp Mole Frac (n-Hexane) 0.0030* 0.0030 0.0000 Comp Mole
Frac (n-Octane) 0.0045* 0.0045 0.0000 Comp Mole Frac (H.sub.2O)
0.0000* 0.0000 0.0000 Purified CO.sub.2 Sour NGL Cooled Sour
Recycle Rich Stream NGL Rich Name Stream 164 264 Stream 266 Comp
Mole Frac (H.sub.2S) 0.0004 0.0008 0.0008 Comp Mole Frac (Nitrogen)
0.0162 0.0000 0.0000 Comp Mole Frac (CO.sub.2) 0.6975 0.0250 0.0250
Comp Mole Frac (Methane) 0.1922 0.0000 0.0000 Comp Mole Frac
(Ethane) 0.0620 0.0613 0.0613 Comp Mole Frac (Propane) 0.0275
0.2670 0.2670 Comp Mole Frac (i-Butane) 0.0017 0.0836 0.0836 Comp
Mole Frac (n-Butane) 0.0024 0.2751 0.2751 Comp Mole Frac
(i-Pentane) 0.0000 0.0697 0.0697 Comp Mole Frac (n-Pentane) 0.0000
0.0858 0.0858 Comp Mole Frac (n-Hexane) 0.0000 0.0527 0.0527 Comp
Mole Frac (n-Octane) 0.0000 0.0790 0.0790 Comp Mole Frac (H.sub.2O)
0.0000 0.0000 0.0000 Low- Pressure Sour NGL Rich Acid Gas NGL Rich
Name Stream 268 Stream 270 Stream 162 Comp Mole Frac (H.sub.2S)
0.0008 0.0315 0.0000 Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO.sub.2) 0.0250 0.9685 0.0000 Comp Mole Frac
(Methane) 0.0000 0.0000 0.0000 Comp Mole Frac (Ethane) 0.0613
0.0000 0.0629 Comp Mole Frac (Propane) 0.2670 0.0000 0.2740 Comp
Mole Frac (i-Butane) 0.0836 0.0000 0.0858 Comp Mole Frac (n-Butane)
0.2751 0.0000 0.2824 Comp Mole Frac (i-Pentane) 0.0697 0.0000
0.0716 Comp Mole Frac (n-Pentane) 0.0858 0.0000 0.0881 Comp Mole
Frac (n-Hexane) 0.0527 0.0000 0.0541 Comp Mole Frac (n-Octane)
0.0790 0.0000 0.0811 Comp Mole Frac (H.sub.2O) 0.0000 0.0000
0.0000
TABLE-US-00006 TABLE 6 Energy Streams Name Heat Flow (Btu/hr)
Condenser Q Energy Stream 282 1.884e+06 Reboiler Q Energy Stream
284 2.211e+06
Example 3
[0079] In a third example, the process simulation was repeated
using a different dehydrated carbon dioxide recycle stream 160. The
material streams, their compositions, and the associated energy
streams produced by the simulation are provided in tables 7, 8, and
9 below, respectively.
TABLE-US-00007 TABLE 7 Material Streams Cooled, Dehydrated Cooled
CO.sub.2 Purified CO.sub.2 CO.sub.2 Recycle Recycle Recycle Name
Stream 160 Stream 252 Stream 258 Vapor Fraction 1.0000 0.9988
1.0000 Temperature (F.) 104.0* 30.00* 4.617 Pressure (psig) 340.0*
335.0 330.0 Molar Flow 17.00* 17.00 16.82 (MMSCFD) Mass Flow
(lb/hr) 8.083e+04 8.083e+04 7.968e+04 Liquid Volume Flow 203.4
203.4 199.5 (USGPM) Heat Flow (Btu/hr) -3.016e+08 -3.032e+08
-3.025e+08 Purified CO.sub.2 Sour NGL Cooled Sour Recycle Rich
Stream NGL Rich Name Stream 164 264 Stream 266 Vapor Fraction
1.0000 0.00000 0.0000 Temperature (F.) 76.45 199.4 120.0* Pressure
(psig) 325.0 340.0 635.3* Molar Flow 16.82 0.1763 0.1763 (MMSCFD)
Mass Flow (lb/hr) 7.968e+04 1153 1153 Liquid Volume Flow 199.5
3.894 3.894 (USGPM) Heat Flow (Btu/hr) -3.009e+08 -1.278e+06
-1.340e+06 Low-Pressure Sour NGL Rich Stream Acid Gas NGL Rich Name
268 Stream 270 Stream 162 Vapor Fraction 0.0000 1.0000 0.0000
Temperature (F.) 120.4 100.0* 115.4 Pressure (psig) 200.3* 5.304*
185.3* Molar Flow 0.1763 0.01048 0.1659 (MMSCFD) Mass Flow (lb/hr)
1153 48.82 1105 Liquid Volume Flow 3.894 0.1188 3.776 (USGPM) Heat
Flow (Btu/hr) -1.340e+06 -1.653e+05 -1.175e+06
TABLE-US-00008 TABLE 8 Stream Compositions Cooled, Dehydrated
Cooled CO.sub.2 Purified CO.sub.2 CO.sub.2 Recycle Recycle Recycle
Name Stream 160 Stream 252 Stream 258 Comp Mole Frac (H.sub.2S)
0.0031* 0.0031 0.0030 Comp Mole Frac (Nitrogen) 0.0008* 0.0008
0.0008 Comp Mole Frac (CO.sub.2) 0.9400* 0.9400 0.9493 Comp Mole
Frac (Methane) 0.0219* 0.0219 0.0222 Comp Mole Frac (Ethane)
0.0156* 0.0156 0.0157 Comp Mole Frac (Propane) 0.0116* 0.0116
0.0088 Comp Mole Frac (i-Butane) 0.0015* 0.0015 0.0002 Comp Mole
Frac (n-Butane) 0.0031* 0.0031 0.0001 Comp Mole Frac (i-Pentane)
0.0007* 0.0007 0.0000 Comp Mole Frac (n-Pentane) 0.0006* 0.0006
0.0000 Comp Mole Frac (n-Hexane) 0.0005* 0.0005 0.0000 Comp Mole
Frac (n-Octane) 0.0006* 0.0006 0.0000 Comp Mole Frac (H.sub.2O)
0.0000* 0.0000 0.0000 Purified CO.sub.2 Sour NGL Cooled Sour
Recycle Rich Stream NGL Rich Name Stream 164 264 Stream 266 Comp
Mole Frac (H.sub.2S) 0.0030 0.0094 0.0094 Comp Mole Frac (Nitrogen)
0.0008 0.0000 0.0000 Comp Mole Frac (CO.sub.2) 0.9493 0.0500 0.0500
Comp Mole Frac (Methane) 0.0222 0.0000 0.0000 Comp Mole Frac
(Ethane) 0.0157 0.0000 0.0000 Comp Mole Frac (Propane) 0.0088
0.2794 0.2794 Comp Mole Frac (i-Butane) 0.0002 0.1265 0.1265 Comp
Mole Frac (n-Butane) 0.0001 0.2985 0.2985 Comp Mole Frac
(i-Pentane) 0.0000 0.0713 0.0713 Comp Mole Frac (n-Pentane) 0.0000
0.0617 0.0617 Comp Mole Frac (n-Hexane) 0.0000 0.0482 0.0482 Comp
Mole Frac (n-Octane) 0.0000 0.0550 0.0550 Comp Mole Frac (H.sub.2O)
0.0000 0.0000 0.0000 Low- Pressure Sour NGL Rich Stream Acid Gas
NGL Rich Name 268 Stream 270 Stream 162 Comp Mole Frac (H.sub.2S)
0.0094 0.1584 0.0000 Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO.sub.2) 0.0500 0.8416 0.0000 Comp Mole Frac
(Methane) 0.0000 0.0000 0.0000 Comp Mole Frac (Ethane) 0.0000
0.0000 0.0000 Comp Mole Frac (Propane) 0.2794 0.0000 0.2970 Comp
Mole Frac (i-Butane) 0.1265 0.0000 0.1345 Comp Mole Frac (n-Butane)
0.2985 0.0000 0.3174 Comp Mole Frac (i-Pentane) 0.0713 0.0000
0.0758 Comp Mole Frac (n-Pentane) 0.0617 0.0000 0.0656 Comp Mole
Frac (n-Hexane) 0.0482 0.0000 0.0512 Comp Mole Frac (n-Octane)
0.0550 0.0000 0.0584 Comp Mole Frac (H.sub.2O) 0.0000 0.0000
0.0000
TABLE-US-00009 TABLE 9 Energy Streams Name Heat Flow (Btu/hr)
Condenser Q Energy Stream 282 6.236e+06 Reboiler Q Energy Stream
284 5.666e+06
Example 4
[0080] In a fourth example, a process simulation was performed
using the NGL recovery/dehydration process 700 shown in FIG. 6. The
simulation was performed using the Bryan Research and Engineering
ProMax software package. The NGL recovery/dehydration process 700
separated the compressed carbon dioxide recycle stream 158 into the
purified carbon dioxide recycle stream 164, the NGL rich stream
162, and the acid gas stream 770. The specified values are
indicated by an asterisk (*). The material streams, their
compositions, and the associated energy streams produced by the
simulation are provided in tables 10, 11, and 12 below,
respectively.
TABLE-US-00010 TABLE 10 Material Streams Compressed Purified Carbon
Cooled Carbon Carbon Dioxide Dioxide Dioxide Recycle Recycle
Recycle Name Stream 158 Stream 752 Stream 164 Temperature (.degree.
F.) 110 55 72.0898 Pressure (psig) 535 532 526.909 Mole Fraction
Vapor (%) 100 97.1149 100 Mole Fraction Light Liquid (%) 0 2.63789
0 Mole Fraction Heavy Liquid (%) 0 0.247192 0 Molecular Weight
(lb/lbmol) 34.5734 34.5734 33.2372 Molar Flow (lbmol/hr) 143.165
143.165 136.153 Vapor Volumetric Flow (ft.sup.3/hr) 1369.35 1144.29
1217.29 Liquid Volumetric Flow (gpm) 170.725 142.665 151.766 Std
Vapor Volumetric Flow 1.30389 1.30389 1.24003 (MMSCFD) Std Liquid
Volumetric Flow (sgpm) 16.1721 16.1721 14.7954 Enthalpy (Btu/hr)
-1.54233E+07 -1.55479E+07 -1.49692E+07 Net Ideal Gas Heating Value
512.476 512.476 391.24 (Btu/ft.sup.3) Cooled, Purified Carbon
Dioxide Dehydrated Recycle Vapor Recycle NGL Rich Name Stream 758
Stream 726 Stream 162 Temperature (.degree. F.) -4.70484 54.9077
121.117 Pressure (psig) 529.909 531 438.3 Mole Fraction Vapor (%)
100 99.9993 0 Mole Fraction Light Liquid (%) 0 0.000671338 100 Mole
Fraction Heavy Liquid (%) 0 0 0 Molecular Weight (lb/lbmol) 33.2372
33.941 65.1996 Molar Flow (lbmol/hr) 136.153 138.957 5.97957 Vapor
Volumetric Flow (ft.sup.3/hr) 880.68 1140.73 10.8305 Liquid
Volumetric Flow (gpm) 109.799 142.221 1.35029 Std Vapor Volumetric
Flow 1.24003 1.26557 0.0544597 (MMSCFD) Std Liquid Volumetric Flow
(sgpm) 14.7954 15.4591 1.2954 Enthalpy (Btu/hr) -1.50938E+07
-1.51048E+07 -405001 Net Ideal Gas Heating Value 391.24 463.982
3359.57 (Btu/ft.sup.3) Sour NGL Cooled, Sour Aqueous Fluid Rich
Stream NGL Rich Name Stream 732 764 Stream 766 Temperature
(.degree. F.) 54.9077 262.193 120 Pressure (psig) 531 531.909
521.909 Mole Fraction Vapor (%) 0 0 0 Mole Fraction Light Liquid
(%) 100 100 100 Mole Fraction Heavy Liquid (%) 0 0 0 Molecular
Weight (lb/lbmol) 18.2988 63.2785 63.2785 Molar Flow (lbmol/hr)
0.354052 6.58207 6.58207 Vapor Volumetric Flow (ft.sup.3/hr)
0.103218 14.3659 11.2331 Liquid Volumetric Flow (gpm) 0.0128688
1.79107 1.40049 Std Vapor Volumetric Flow 0.00322458 0.0599471
0.0599471 (MMSCFD) Std Liquid Volumetric Flow (sgpm) 0.013039
1.36091 1.36091 Enthalpy (Btu/hr) -43829.7 -468892 -508612 Net
Ideal Gas Heating Value 0.450311 3053.71 3053.71 (Btu/ft.sup.3)
Low-Pressure Sour NGL Rich Stream Name 768 Acid Gases 770
Temperature (.degree. F.) 120.145 120 Pressure (psig) 441.3 12.3041
Mole Fraction Vapor (%) 0 100 Mole Fraction Light Liquid (%) 100 0
Mole Fraction Heavy Liquid (%) 0 0 Molecular Weight (lb/lbmol)
63.2785 42.366 Molar Flow (lbmol/hr) 6.58207 0.645859 Vapor
Volumetric Flow (ft.sup.3/hr) 11.2586 147.542 Liquid Volumetric
Flow (gpm) 1.40367 18.3949 Std Vapor Volumetric Flow 0.0599471
0.00588224 (MMSCFD) Std Liquid Volumetric Flow (sgpm) 1.36091
0.0667719 Enthalpy (Btu/hr) -508612 -106053 Net Ideal Gas Heating
Value 3053.71 9.39946 (Btu/ft.sup.3)
TABLE-US-00011 TABLE 11 Stream Compositions Compressed Purified
Carbon Cooled Carbon Carbon Dioxide Dioxide Dioxide Recycle Recycle
Recycle Name Stream 158 Stream 752 Stream 164 Comp Molar Flow
H.sub.2S (lb.sub.mol/hr) 0 0 0 Comp Molar Flow Nitrogen 5.42488
5.42488 5.42487 (lb.sub.mol/hr) Comp Molar Flow CO.sub.2
(lb.sub.mol/hr) 78.374 78.374 77.7679 Comp Molar Flow Methane
46.8833 46.8833 46.8831 (lb.sub.mol/hr) Comp Molar Flow Ethane
(lb.sub.mol/hr) 5.04264 5.04264 4.97376 Comp Molar Flow Propane
(lb.sub.mol/hr) 2.60218 2.60218 1.06689 Comp Molar Flow i-Butane
0.632167 0.632167 0.0262049 (lb.sub.mol/hr) Comp Molar Flow
n-Butane 1.01441 1.01441 0.0106494 (lb.sub.mol/hr) Comp Molar Flow
i-Pentane 0.543958 0.543958 2.47836E-05 (lb.sub.mol/hr) Comp Molar
Flow n-Pentane 0.27933 0.27933 6.5645E-06 (lb.sub.mol/hr) Comp
Molar Flow n-Hexane 1.94061 1.94061 6.8325E-08 (lb.sub.mol/hr) Comp
Molar Flow n-Heptane 0 0 0 (lb.sub.mol/hr) Comp Molar Flow H.sub.2O
(lb.sub.mol/hr) 0.427428 0.427428 1.88221E-05 Comp Molar Flow
Diethyle Amine 0 0 0 (lb.sub.mol/hr) Cooled, Purified Carbon
Dioxide Dehydrated Recycle Vapor Recycle NGL Rich Name Stream 758
Stream 726 Stream 162 Comp Molar Flow H.sub.2S (lb.sub.mol/hr) 0 0
0 Comp Molar Flow Nitrogen 5.42487 5.41324 5.81573E-09
(lb.sub.mol/hr) Comp Molar Flow CO.sub.2 (lb.sub.mol/hr) 77.7679
77.1797 1.75658E-06 Comp Molar Flow Methane 46.8831 46.6143
2.21379E-05 (lb.sub.mol/hr) Comp Molar Flow Ethane (lb.sub.mol/hr)
4.97376 4.89657 0.068452 Comp Molar Flow Propane (lb.sub.mol/hr)
1.06689 2.39516 1.53245 Comp Molar Flow i-Butane 0.0262049 0.529946
0.605608 (lb.sub.mol/hr) Comp Molar Flow n-Butane 0.0106494
0.799268 1.00312 (lb.sub.mol/hr) Comp Molar Flow i-Pentane
2.47836E-05 0.345064 0.543843 (lb.sub.mol/hr) Comp Molar Flow
n-Pentane 6.5645E-06 0.161123 0.279274 (lb.sub.mol/hr) Comp Molar
Flow n-Hexane 6.8325E-08 0.622204 1.9405 (lb.sub.mol/hr) Comp Molar
Flow n-Heptane 0 0 0 (lb.sub.mol/hr) Comp Molar Flow H.sub.2O
(lb.sub.mol/hr) 1.88221E-05 0.000761257 0.0062375 Comp Molar Flow
Diethyle Amine 0 0 7.30571E-05 (lb.sub.mol/hr) Sour NGL Cooled,
Sour Aqueous Fluid Rich Stream NGL Rich Name Stream 732 764 Stream
766 Comp Molar Flow H.sub.2S (lb.sub.mol/hr) 0 0 0 Comp Molar Flow
Nitrogen 7.93825E-06 5.94147E-09 5.94147E-09 (lb.sub.mol/hr) Comp
Molar Flow CO.sub.2 (lb.sub.mol/hr) 0.00385078 0.602328 0.602328
Comp Molar Flow Methane 0.000125243 2.25954E-05 2.25954E-05
(lb.sub.mol/hr) Comp Molar Flow Ethane (lb.sub.mol/hr) 1.31496E-05
0.0688655 0.0688655 Comp Molar Flow Propane (lb.sub.mol/hr)
6.92895E-06 1.53528 1.53528 Comp Molar Flow i-Butane 4.43906E-07
0.605962 0.605962 (lb.sub.mol/hr) Comp Molar Flow n-Butane
1.35201E-06 1.00376 1.00376 (lb.sub.mol/hr) Comp Molar Flow
i-Pentane 3.68843E-07 0.543932 0.543932 (lb.sub.mol/hr) Comp Molar
Flow n-Pentane 1.57397E-07 0.279323 0.279323 (lb.sub.mol/hr) Comp
Molar Flow n-Hexane 1.94686E-07 1.9406 1.9406 (lb.sub.mol/hr) Comp
Molar Flow n-Heptane 0 0 0 (lb.sub.mol/hr) Comp Molar Flow H.sub.2O
(lb.sub.mol/hr) 0.350046 0.00199881 0.00199881 Comp Molar Flow
Diethyle Amine 0 0 0 (lb.sub.mol/hr) Low-Pressure Sour NGL Rich
Stream Name 768 Acid Gases 770 Comp Molar Flow H.sub.2S
(lb.sub.mol/hr) 0 0 Comp Molar Flow Nitrogen 5.94147E-09 0
(lb.sub.mol/hr) Comp Molar Flow CO.sub.2 (lb.sub.mol/hr) 0.602328
0.602272 Comp Molar Flow Methane 2.25954E-05 2.56258E-07
(lb.sub.mol/hr) Comp Molar Flow Ethane (lb.sub.mol/hr) 0.0688655
0.000254578 Comp Molar Flow Propane (lb.sub.mol/hr) 1.53528
0.00159919 Comp Molar Flow i-Butane 0.605962 0.00016306
(lb.sub.mol/hr) Comp Molar Flow n-Butane 1.00376 0.000353691
(lb.sub.mol/hr) Comp Molar Flow i-Pentane 0.543932 3.41627E-05
(lb.sub.mol/hr) Comp Molar Flow n-Pentane 0.279323 2.16905E-05
(lb.sub.mol/hr) Comp Molar Flow n-Hexane 1.9406 4.4341E-05
(lb.sub.mol/hr) Comp Molar Flow n-Heptane 0 0 (lb.sub.mol/hr) Comp
Molar Flow H.sub.2O (lb.sub.mol/hr) 0.00199881 0.0411157 Comp Molar
Flow Diethyle Amine 0 4.17895E-20 (lb.sub.mol/hr)
TABLE-US-00012 TABLE 12 Energy Streams Name Heat Flow (Btu/hr)
Condenser Energy Stream 782 320524 Reboiler Energy Stream 784
253961
Example 5
[0081] In a fifth example, the process simulation was continued for
the NGL upgrade process 500 shown in FIG. 4. The simulation was
performed using the Aspen Tech. HYSYS Version 7.2 (previously
Hyprotech Ltd. HYSYS) software package. The NGL upgrade process 500
separates the NGL rich stream 162 into the heavy NGL stream 172 and
the light NGL stream 174. In the following tables and results, the
low-pressure sour NGL rich stream 268 has the composition as
determined by the simulation model of the low-pressure sour NGL
rich stream 768 from Example 4. Similarly, the acid gas stream 270
has the composition as determined by the simulation model of the
acid gas stream 770 from Example 4. In addition, the NGL rich
stream 162 has the composition as determined by the simulation
model of the NGL rich stream 162 from Example 4. The material
streams, their compositions, and the associated energy streams
produced by the simulation are provided in tables 13, 14, and 15
below, respectively.
TABLE-US-00013 TABLE 13 Material Streams Low-Pressure Sour NGL Rich
Stream Acid Gas NGL Rich Name 268 Stream 270 Stream 162 Vapor
Fraction 0.0000 1.0000 0.0000 Temperature (F.) 120.145 120.0 94.16
Pressure (psig) 441.3 12.3041 250.0 Molar Flow (MMSCFD) 0.321888
5.8822e-002 1.019 Mass Flow (lb/hr) 416.5033 27.362473 7567
Standard Liquid Volume 46.6598 2.2893 840.0 Flow (barrel/day) Heat
Flow (Btu/hr) -508612 -106053 -7.920e+006 Cooled, Overhead Heavy
NGL Light NGL Heavy NGL Name Stream 524 Stream 514 Stream 174
Stream 172 Vapor Fraction 1.0000 0.0000 0.0000 0.0000 Temperature
185.7 270.6 134.0 100.0 (F.) Pressure (psig) 160.0 165.0 155.0
160.0 Molar Flow 0.3687 0.6507 0.3687 0.6507 (MMSCFD) Mass Flow
2186 5381 2186 5381 (lb/hr) Standard 266.4 576.5 266.4 576.5 Liquid
Volume Flow (barrel/day) Heat Flow -2.029e+006 -4.885e+006
-2.367e+006 -5.478e+006 (Btu/hr)
TABLE-US-00014 TABLE 14 Stream Compositions Low-Pressure Sour NGL
Rich Stream Acid Gas NGL Rich Name 268 Stream 270 Stream 162 Comp
Mole Frac (H.sub.2S) 0.0000 Comp Mole Frac (Nitrogen) 0.0000 Comp
Mole Frac (CO.sub.2) 0.09151 0.93251 0.0000 Comp Mole Frac
(Methane) 0.00000 0.00000 0.0000 Comp Mole Frac (Ethane) 0.01046
0.00039 0.0027 Comp Mole Frac (Propane) 0.23325 0.00248 0.1653 Comp
Mole Frac (i-Butane) 0.09206 0.00025 0.0756 Comp Mole Frac
(n-Butane) 0.15250 0.00055 0.2423 Comp Mole Frac (i-Pentane)
0.08264 0.00005 0.1092 Comp Mole Frac (n-Pentane) 0.04244 0.00003
0.0915 Comp Mole Frac (n-Hexane) 0.29483 0.00007 0.2943 Comp Mole
Frac (n-Heptane) 0.00000 0.00000 0.0191 Comp Mole Frac (n-Octane)
-- -- 0.0000 Comp Mole Frac (H.sub.2O) 0.00030 0.06366 0.0000
Cooled, Overhead Heavy NGL Light NGL Heavy NGL Name Stream 524
Stream 514 Stream 174 Stream 172 Comp Mole Frac (H.sub.2S) 0.0000
0.0000 0.0000 0.0000 Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
0.0000 Comp Mole Frac (CO.sub.2) 0.0000 0.0000 0.0000 0.0000 Comp
Mole Frac (Methane) 0.0000 0.0000 0.0000 0.0000 Comp Mole Frac
(Ethane) 0.0075 0.0000 0.0075 0.0000 Comp Mole Frac (Propane)
0.4547 0.0013 0.4547 0.0013 Comp Mole Frac (i-Butane) 0.1330 0.0431
0.1330 0.0431 Comp Mole Frac (n-Butane) 0.2751 0.2236 0.2751 0.2236
Comp Mole Frac (i-Pentane) 0.0486 0.1435 0.0486 0.1435 Comp Mole
Frac (n-Pentane) 0.0359 0.1230 0.0359 0.1230 Comp Mole Frac
(n-Hexane) 0.0437 0.4363 0.0437 0.4363 Comp Mole Frac (n-Heptane)
0.0013 0.0292 0.0013 0.0292 Comp Mole Frac (n-Octane) 0.0000 0.0000
0.0000 0.0000 Comp Mole Frac (H.sub.2O) 0.0000 0.0000 0.0000
0.0000
TABLE-US-00015 TABLE 15 Energy Streams Name Heat Flow (Btu/hr)
Reboiler Energy Stream 516 25.4 .times. 10.sup.3 Cooling Fluid
Stream 522 39.72 .times. 10.sup.3
[0082] At least one embodiment is disclosed and variations,
combinations, and/or modifications of the embodiment(s) and/or
features of the embodiment(s) made by a person having ordinary
skill in the art are within the scope of the disclosure.
Alternative embodiments that result from combining, integrating,
and/or omitting features of the embodiment(s) are also within the
scope of the disclosure. Where numerical ranges or limitations are
expressly stated, such express ranges or limitations should be
understood to include iterative ranges or limitations of like
magnitude falling within the expressly stated ranges or limitations
(e.g., from about 1 to about 10 includes, 2, 3, 4, etc.; greater
than 0.10 includes 0.11, 0.12, 0.13, etc.). For example, whenever a
numerical range with a lower limit, R.sub.1, and an upper limit,
R.sub.u, is disclosed, any number falling within the range is
specifically disclosed. In particular, the following numbers within
the range are specifically disclosed:
R=R.sub.1+k*(R.sub.u-R.sub.1), wherein k is a variable ranging from
1 percent to 100 percent with a 1 percent increment, e.g., k is 1
percent, 2 percent, 3 percent, 4 percent, 5 percent, . . . , 50
percent, 51 percent, 52 percent, . . . , 95 percent, 96 percent, 97
percent, 98 percent, 99 percent, or 100 percent. Moreover, any
numerical range defined by two R numbers as defined in the above is
also specifically disclosed. Use of the term "optionally" with
respect to any element of a claim means that the element is
required, or alternatively, the element is not required, both
alternatives being within the scope of the claim. Use of broader
terms such as comprises, includes, and having should be understood
to provide support for narrower terms such as consisting of,
consisting essentially of, and comprised substantially of.
Accordingly, the scope of protection is not limited by the
description set out above but is defined by the claims that follow,
that scope including all equivalents of the subject matter of the
claims. Each and every claim is incorporated as further disclosure
into the specification and the claims are embodiment(s) of the
present disclosure. The discussion of a reference in the disclosure
is not an admission that it is prior art, especially any reference
that has a publication date after the priority date of this
application. The disclosure of all patents, patent applications,
and publications cited in the disclosure are hereby incorporated by
reference, to the extent that they provide exemplary, procedural,
or other details supplementary to the disclosure.
[0083] While several embodiments have been provided in the present
disclosure, it should be understood that the disclosed systems and
methods might be embodied in many other specific forms without
departing from the spirit or scope of the present disclosure. The
present examples are to be considered as illustrative and not
restrictive, and the intention is not to be limited to the details
given herein. For example, the various elements or components may
be combined or integrated in another system or certain features may
be omitted, or not implemented.
[0084] In addition, techniques, systems, subsystems, and methods
described and illustrated in the various embodiments as discrete or
separate may be combined or integrated with other systems, modules,
techniques, or methods without departing from the scope of the
present disclosure. Other items shown or discussed as coupled or
directly coupled or communicating with each other may be indirectly
coupled or communicating through some interface, device, or
intermediate component whether electrically, mechanically, or
otherwise. Other examples of changes, substitutions, and
alterations are ascertainable by one skilled in the art and could
be made without departing from the spirit and scope disclosed
herein.
* * * * *