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Patent 2949015 Summary

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(12) Patent: (11) CA 2949015
(54) English Title: ENHANCED NATURAL GAS LIQUID RECOVERY PROCESS
(54) French Title: PROCESSUS DE RECUPERATION AMELIORE DU GAZ NATUREL SOUS FORME LIQUIDE
Status: Granted
Bibliographic Data
(51) International Patent Classification (IPC):
  • E21B 43/34 (2006.01)
  • C10L 3/10 (2006.01)
  • E21B 43/16 (2006.01)
  • E21B 43/40 (2006.01)
  • F25J 1/00 (2006.01)
  • F25J 3/00 (2006.01)
(72) Inventors :
  • PRIM, ERIC (United States of America)
  • BAKER, NAOMI (United States of America)
  • GARIKIPATI, JHANSI (United States of America)
(73) Owners :
  • PILOT ENERGY SOLUTIONS, LLC (United States of America)
(71) Applicants :
  • PILOT ENERGY SOLUTIONS, LLC (United States of America)
(74) Agent: GOWLING WLG (CANADA) LLP
(74) Associate agent:
(45) Issued: 2019-09-17
(22) Filed Date: 2011-05-06
(41) Open to Public Inspection: 2012-10-28
Examination requested: 2016-11-17
Availability of licence: N/A
(25) Language of filing: English

Patent Cooperation Treaty (PCT): No

(30) Application Priority Data:
Application No. Country/Territory Date
13/096,788 United States of America 2011-04-28

Abstracts

English 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 C3+ 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.


French Abstract

Une méthode comprend la réception dun flux dalimentation dhydrocarbure; la séparation du flux dalimentation dhydrocarbure dans un flux riche en hydrocarbure lourd et un flux de recyclage, où le flux de recyclage comprend un gaz sélectionné parmi le groupe comprenant le dioxyde de carbone, lazote, lair et leau; et la séparation du flux de recyclage dans un flux riche en liquides de gaz naturel (LGN) et un flux de recyclage purifié. Une pluralité déquipements de traitement sont configurés pour recevoir un flux dalimentation dhydrocarbure; séparer le flux dalimentation dhydrocarbure dans un flux riche en hydrocarbure lourd et un flux de recyclage renfermant au moins un hydrocarbure C3+ et un gaz sélectionné parmi le groupe comprenant le dioxyde de carbone, lazote, lair et leau; et séparer le flux de recyclage dans un flux riche en liquides de gaz naturel (LGN) et un flux de recyclage purifié.

Claims

Note: Claims are shown in the official language in which they were submitted.



CLAIMS

1. A method comprising:
receiving a feed stream including hydrocarbons and carbon dioxide;
separating the feed stream into a vapor stream, a liquid stream, and a water
stream; and
directing the vapor stream and the liquid stream to a column,
wherein the column produces a natural gas liquids (NGL) rich stream and a
purified carbon
dioxide-rich stream, and
wherein the purified carbon dioxide-rich stream includes less than 5 molar
percent C3
hydrocarbons and at least 90 molar percent carbon dioxide.
2. The method of claim 1, wherein the NGL rich stream comprises C3+
hydrocarbons and
hydrogen sulfide.
3. The method of claim 1, further comprising cooling the feed stream with
the purified carbon
dioxide-rich stream.
4. The method of claim 1, further comprising:
adding a dehydration solvent to the vapor stream; and
subsequently removing the dehydration solvent from the vapor stream to produce
a dry
vapor stream, wherein the dry vapor stream is substantially free of water.
5. The method of claim 1, further comprising sending the purified carbon
dioxide-rich stream
to a compressor that compresses the purified carbon dioxide-rich stream until
the purified carbon

53


dioxide-rich stream is suitable for injection into a subterranean formation,
wherein the compressed
purified carbon dioxide-rich stream is subsequently injected into the
subterranean formation, and
wherein the purified carbon dioxide-rich stream is not demethanized between
being produced by
the column and being injected into the subterranean formation.
6. The method of claim 1, further comprising sweetening the NGL rich stream
by separating
the NGL-rich stream into a sweet NGL rich stream and an acid gas stream.
7. The method of claim 6, further comprising:
cooling the NGL rich stream prior to sweetening the NGL rich stream; and
throttling the NGL rich stream prior to sweetening the NGL rich stream, and
wherein receiving the feed stream includes receiving a plurality of the feed
streams from a
plurality of different natural gas liquid sources.
8. The method of claim 6, wherein the sweet NGL rich stream comprises no
more than 5
molar percent hydrogen sulfide.
9. The method of claim 7, further comprising:
separating heavy hydrocarbons from the feed stream prior to cooling the feed
stream,
wherein the heavy hydrocarbons include C9+ hydrocarbons, branched
hydrocarbons, and/or
aromatic hydrocarbons;
separating the sweet NGL rich stream into a heavy NGL stream and a light NGL
stream;
and

54


mixing the heavy NGL stream with the heavy hydrocarbons.
10. The method of claim 9, wherein the light NGL stream has a vapor
pressure of less than 250
pounds per square inch gauge (psig) at a temperature of 100 degrees
Fahrenheit.
11. The method of claim 9, further comprising combining a second NGL rich
stream with the
NGL rich stream and/or the sweet NGL-rich stream prior to separating the sweet
NGL rich stream.
12. A plurality of process equipment configured to:
receive a feed stream comprising hydrocarbons and carbon dioxide;
separate the cooled feed stream into a vapor stream, a liquid stream, and a
water stream in a
three-phase separator; and
direct the vapor stream and the liquid stream to a column,
wherein the column produces a natural gas liquids (NGL) rich stream and the
purified
carbon dioxide-rich stream,
wherein the NGL rich stream includes C3+ hydrocarbons and hydrogen sulfide,
wherein the process equipment is further configured to separate heavy
hydrocarbons from
the feed stream prior to separating the feed stream,
wherein the heavy hydrocarbons include C9+ hydrocarbons, and
wherein the process equipment is 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 hydrocarbons.



13. The process equipment of claim 12, wherein the process equipment is
further configured to
combine a second NGL rich stream with the NGL rich stream prior to separating
the NGL rich
stream.
14. The method of claim 3, wherein the purified carbon dioxide recycle
stream is not subjected
to any process steps other than reflux between being produced by the column
and cooling the feed
stream.
15. The method of claim 14, wherein the feed stream, the cooled feed
stream, the liquid stream,
and the purified carbon dioxide recycle stream are not subjected to cryogenic
conditions,
membranes, and carbon dioxide recovery solvents.
16. The method of claim 1, wherein the purified carbon dioxide-rich stream
comprises at least
99 molar percent of the methane from the feed stream.
17. The method of claim 5, wherein the purified carbon dioxide-rich stream
is not subjected to
any solvents, membranes, or cryogenic conditions between being produced by the
column and
being injected into the subterranean formation.
18. A plurality of process equipment configured to:
receive a feed stream comprising hydrocarbons and carbon dioxide;

56


separate the feed stream into a vapor stream, a liquid stream, and a water
stream in a three
phase separator; and
direct the vapor stream and the liquid stream to a column,
wherein the column produces a natural gas liquids (NGL) rich stream and the
purified
carbon dioxide-rich stream,
wherein the NGL rich stream includes C3+ hydrocarbons and hydrogen sulfide,
wherein the purified carbon dioxide recycle stream is not subjected to any
process steps
other than reflux between being produced by the column and separating the feed
stream,
wherein the process equipment is further configured to send the purified
carbon dioxide-
rich stream to a compressor that compresses the purified carbon dioxide-rich
stream until the
purified carbon dioxide-rich stream is suitable for injection into a
subterranean formation,
wherein the compressed purified carbon dioxide-rich stream is subsequently
injected into
the subterranean formation,
wherein the purified carbon dioxide-rich stream is not demethanized between
being
produced by the column and being injected into the subterranean formation,
wherein the process equipment is further configured to:
add a dehydration solvent to the vapor stream; and
subsequently remove the dehydration solvent from the vapor stream to produce a
dry vapor stream,
wherein the dry vapor stream is substantially free of water,
wherein the dry vapor stream is directed to the column,
wherein the process equipment is further configured to sweeten the NGL rich
stream,
thereby producing a sweet NGL rich stream, and

57


wherein the purified carbon dioxide-rich stream comprises at least 99 molar
percent of the
methane from the feed stream.
19. The process equipment of claim 18, wherein the purified carbon dioxide-
rich stream is not
subjected to any solvents, membranes, or cryogenic conditions between being
produced by the
column and being injected into the subterranean formation.
20. The method of claim 1, further comprising dehydrating the liquid stream
after separating
the liquid phase in the three-phase separator and before directing the liquid
stream to the column.
21. The method of claim 1, further comprising sending the NGL rich stream
to a heat
exchanger and a throttle valve to reduce a temperature and a pressure of the
NGL rich stream and
then separating the NGL rich stream into an acid gas stream and a sweet NGL
rich stream, wherein
the acid gas stream includes substantially all of the hydrogen sulfide from
the feed stream.
22. The method of claim 1, further comprising:
sending the NGL rich stream to a separator to separate the NGL rich stream
into a light
NGL rich stream and a heavy NGL rich stream; and
blending the heavy NGL rich stream from the separator with a heavy hydrocarbon
stream
to produce an upgraded NGL rich stream.

58


23. The method of claim 22, wherein the separator comprises a stripping
column and a
reboiler, and wherein the reboiler comprises a shell and tube heat exchanger
coupled to a hot oil
heater.
24. A set of process equipment configured to:
receive a feed stream including hydrocarbons and carbon dioxide;
separate the feed stream into a vapor stream, a liquid stream, and a water
stream; and
direct the vapor stream and the liquid stream to a column,
wherein the column produces a natural gas liquids (NGL) rich stream and a
purified carbon
dioxide-rich stream, and
wherein the purified carbon dioxide-rich stream includes less than 5 molar
percent C3
hydrocarbons and at least 90 molar percent carbon dioxide.
25. The set of process equipment of claim 24, wherein the NGL rich stream
comprises C3+
hydrocarbons and hydrogen sulfide.
26. The set of process equipment of claim 24, further configured to cool
the feed stream with
the purified carbon dioxide-rich stream.
27. The set of process equipment of claim 26, wherein the purified carbon
dioxide recycle
stream is not subjected to any process steps other than reflux between being
produced by the
column and cooling the feed stream.

59


28. The set of process equipment of claim 27, wherein the feed stream, the
cooled feed stream,
the liquid stream, and the purified carbon dioxide recycle stream are not
subjected to cryogenic
conditions, membranes, and carbon dioxide recovery solvents.
29. The set of process equipment of claim 24, further configured to:
add a dehydration solvent to the vapor stream; and
subsequently remove the dehydration solvent from the vapor stream to produce a
dry vapor
stream, wherein the dry vapor stream is substantially free of water.
30. The set of process equipment of claim 24, further configured to send
the purified carbon
dioxide-rich stream to a compressor that compresses the purified carbon
dioxide-rich stream until
the purified carbon dioxide-rich stream is suitable for injection into a
subterranean formation,
wherein the compressed purified carbon dioxide-rich stream is subsequently
injected into the
subterranean formation, and wherein the purified carbon dioxide-rich stream is
not demethanized
between being produced by the column and being injected into the subterranean
formation.
31. The set of process equipment of claim 30, wherein the purified carbon
dioxide-rich stream
is not subjected to any solvents, membranes, or cryogenic conditions between
being produced by
the column and being injected into the subterranean formation.
32. The set of process equipment of claim 24, further configured to sweeten
the NGL
rich stream by separating the NGL-rich stream into a sweet NGL rich stream and
an acid gas
stream.



33. The set of process equipment of claim 32, further configured to:
cool the NGL rich stream prior to sweetening the NGL rich stream; and
throttle the NGL rich stream prior to sweetening the NGL rich stream, and
wherein receiving the feed stream includes receiving a plurality of the feed
streams from a
plurality of different natural gas liquid sources.
34. The set of process equipment of claim 32, wherein the sweet NGL rich
stream comprises
no more than 5 molar percent hydrogen sulfide.
35. The set of process equipment of claim 33, further configured to:
separate heavy hydrocarbons from the feed stream prior to cooling the feed
stream, wherein
the heavy hydrocarbons include C9+ hydrocarbons, branched hydrocarbons, and/or
aromatic
hydrocarbons;
separate the sweet NGL rich stream into a heavy NGL stream and a light NGL
stream; and
mix the heavy NGL stream with the heavy hydrocarbons.
36. The set of process equipment of claim 35, wherein the light NGL stream
has a vapor
pressure of less than 250 pounds per square inch gauge (psig) at a temperature
of 100 degrees
Fahrenheit.

61


37. The set of process equipment of claim 35, further configured to combine
a second NGL
rich stream with the NGL rich stream and/or the sweet NGL-rich stream prior to
separating the
sweet NGL rich stream.
38. The set of process equipment of claim 24, wherein the purified carbon
dioxide-rich stream
comprises at least 99 molar percent of the methane from the feed stream.
39. The set of process equipment of claim 24, further configured to
dehydrate the liquid stream
after separating the liquid phase in the three-phase separator and before
directing the liquid stream
to the column.
40. The set of process equipment of claim 24, further configured to send
the NGL rich stream
to a heat exchanger and a throttle valve to reduce a temperature and a
pressure of the NGL rich
stream and then separating the NGL rich stream into an acid gas stream and a
sweet NGL rich
stream, wherein the acid gas stream includes substantially all of the hydrogen
sulfide from the feed
stream.
41. The set of process equipment of claim 24, further configured to:
send the NGL rich stream to a separator to separate the NGL rich stream into a
light NGL
rich stream and a heavy NGL rich stream; and
blend the heavy NGL rich stream from the separator with a heavy hydrocarbon
stream to
produce an upgraded NGL rich stream.

62


42. The set
of process equipment of claim 41, wherein the separator comprises a stripping
column and a reboiler, and wherein the reboiler comprises a shell and tube
heat exchanger
coupled to a hot oil heater.

63

Description

Note: Descriptions are shown in the official language in which they were submitted.


CA 02949015 2016-11-17
ENHANCED NATURAL GAS LIQUID RECOVERY PROCESS
BACKGROUND
Carbon dioxide (CO2) 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
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.
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 C3+
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 C3+
hydrocarbons from
the recycle stream.
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.
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

CA 02949015 2016-11-17
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.
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 C3+
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
FIG. 1 is a process flow diagram for an embodiment of a carbon dioxide
reinjection
process.
FIG. 2 is a schematic diagram of an embodiment of a NGL recovery process.
FIG. 3 is a chart depicting an embodiment of the relationship between the NGL
recovery
rate and the energy requirement.
FIG. 4 is a schematic diagram of an embodiment of a NGL upgrade process.
FIG. 5 is a process flow diagram for another embodiment of a reinjection
process.
FIG. 6 is a schematic diagram of another embodiment of a NGL recovery process.
FIG. 7 is a flowchart of an embodiment of a NGL recovery optimization method.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
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.
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
2

CA 02949015 2016-11-17
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.
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.
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.
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 (H2S), 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
3

CA 02949015 2016-11-17
includes methane and ethane, but also may include diminishing amounts of C3 ¨
C8 hydrocarbons.
The term "natural gas liquids" or NGLs may refer to natural gases that may be
liquefied without
refrigeration, and may include C3 ¨ C8 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 C9+ hydrocarbons,
branched
hydrocarbons, aromatic hydrocarbons, and combinations thereof.
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.
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
4

CA 02949015 2016-11-17
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.
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.
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.
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

CA 02949015 2016-11-17
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.
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.
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.
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
6

CA 02949015 2016-11-17
percent, or substantially all of the C4+ 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 C3+
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.
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 Figure 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 Figure 4. A
specific example of a
suitable NGL upgrade process 170 is shown in FIG. 5 and described in further
detail below.
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
7

CA 02949015 2016-11-17
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 C34-. 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
percent, or be substantially free of C2+.
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.
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
8

CA 02949015 2016-11-17
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 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 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).
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.
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
9

CA 02949015 2016-11-17
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.
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.
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

CA 02949015 2016-11-17
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.
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.
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.
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
II

CA 02949015 2016-11-17
NGL recovery rate may be a percentage recovery, and may represent the amount
of C3+ 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.
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 C3+ may require substantially
less energy than
recovering a second amount 306 of from about 40 percent to about 65 percent of
C3+. Moreover,
recovering the second amount 306 of from about 40 percent to about 65 percent
of C3+ may require
substantially less energy than recovering a third amount 308 of from about 70
percent to about
90 percent of C3+. 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 C3+, 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.
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
12

CA 02949015 2016-11-17
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.
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.
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
13

CA 02949015 2016-11-17
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.
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.
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
14

CA 02949015 2016-11-17
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.
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.
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

CA 02949015 2016-11-17
foot (Btu/ft3) and about 1,200 Btu/ft3, or alternatively between about 1,050
Btu/ft3 and about
1,100 Btu/ft3. 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 F. Based on the applicable thresholds,
the composition and
the fiowrate 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.
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.
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.
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.
16

CA 02949015 2016-11-17
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.
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.
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.
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
17

CA 02949015 2016-11-17
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.
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.
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
18

CA 02949015 2016-11-17
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.
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.
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.
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
19

CA 02949015 2016-11-17
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.
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.
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.
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

CA 02949015 2016-11-17
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.
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.
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
21

CA 02949015 2016-11-17
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.
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.
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.
22

CA 02949015 2016-11-17
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.
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 l
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.
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.
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.
23

CA 02949015 2016-11-17
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.
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.
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.
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.
In an embodiment, the equipment size may be configured to allow for variations
in
recovery rates to accommodate changes in economic conditions, such as C3+ or
energy pricing.
24

CA 02949015 2016-11-17
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
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.
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
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

CA 02949015 2016-11-17
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
Stream 160 Stream 252
Stream 258
Liquid Volume Flow (USGPM) 218.1 218.1 192.3
Heat Flow (Btu/hr) -2.639e+08 -2.658e+08
-2.577e+08
Table IA: Material Streams
Purified CO2 Sour NGL Cooled Sour
Name Recycle Rich Stream NGL Rich
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 (USGPM) 192.3 25.84 25.84
Heat Flow (Btu/hr) -2.558e+08 -8.443e+06
-8.862e+06
Table 1B: Material Streams
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
Vapor Fraction 0.0000 1.0000 0.0000
Temperature (F) 120.9 100.0* 111.8
26

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
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 (USGPM) 25.84 1.100 24.74
Heat Flow (Btu/hr) -8.862e+06 -1.083e+06
-7.779e+06
Table 1C: Material Streams
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
Stream 160 Stream 252
Stream 258
Comp Mole Frac (H2S) 0.0333* 0.0333 0.0327
Comp Mole Frac (Nitrogen) 0.0054* 0.0054 0.0058
Comp Mole Frac (CO2) 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 (H20) 0.0000* 0.0000 0.0000
Table 2A: Stream Compositions
27

CA 02949015 2016-11-17
Purified CO2 Sour NGL Cooled Sour
Name Recycle Rich Stream NGL Rich
Stream 164 264 Stream 266
Comp Mole Frac (H2S) 0.0327 0.0421 0.0421
Comp Mole Frac (Nitrogen) 0.0058 0.0000 0.0000
Comp Mole Frac (CO2) 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 (H2O) 0.0000 0.0000 0.0000
Table 2B: Stream Compositions
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
Comp Mole Frac (H2S) 0.0421 0.4568 0.0000
Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO2) 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
28

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
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 (H20) 0.0000 0.0000 0.0000
Table 2C: Stream Compositions
Name Heat Flow (Btu/hr)
Condenser Q Energy Stream 282 1.469e+06
Reboiler Q Energy Stream 284 1.152e+06
Table 3: Energy Streams
EXAMPLE 2
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.
29

CA 02949015 2016-11-17
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
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 (MMSCFD) 20.00* 20.00 18.86
Mass Flow (lb/hr) 8.535e+04 8.535e+04 7.780e+04
Liquid Volume Flow (USGPM) 258.0 258.0 232.2
Heat Flow (Btu/hr) -2.741e+08 -2.760e+08
-2.683e+08
Table 4A: Material Streams
Purified CO2 Sour NGL Cooled Sour
Name Recycle Rich Stream NGL Rich
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 (MMSCFD) 18.86 1.139 1.139
Mass Flow (lb/hr) 7.780e+04 7552 7552
Liquid Volume Flow (USGPM) 232.2 25.83 25.83
Heat Flow (Btu/hr) -2.663e+08 -7.411e+06
-8.371e+06
Table 4B: Material Streams
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
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 (MMSCFD) 1.139 0.02943 1.110
Mass Flow (lb/hr) 7552 141.2 7411
Liquid Volume Flow (USGPM) 25.83 0.3421 25.49
-Heat Flow (Btu/hr) -8.371e+06 -5.301e+05
-7.841e+06
Table 4C: Material Streams
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
Stream 160 Stream 252
Stream 258
Comp Mole Frac (H2S) 0.0004* 0.0004 0.0004
Comp Mole Frac (Nitrogen) 0.0153* 0.0153 0.0162
Comp Mole Frac (CO2) 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
31

CA 02949015 2016-11-17
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
Stream 160 Stream 252
Stream 258
Comp Mole Frac (H20) 0.0000* 0.0000 0.0000
Table 5A: Stream Compositions
Purified CO2 Sour NGL Cooled Sour
Name Recycle Rich Stream NGL Rich
Stream 164 264 Stream 266
Comp Mole Frac (H2S) 0.0004 0.0008 0.0008
Comp Mole Frac (Nitrogen) 0.0162 0.0000 0.0000
Comp Mole Frac (CO2) 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 (H20) 0.0000 0.0000 0.0000
Table 5B: Stream Compositions
32

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
Comp Mole Frac (H2S) 0.0008 0.0315 0.0000
Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO2) 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 (H20) 0.0000 0.0000 0.0000
Table SC: Stream Compositions
Name Heat Flow (Btu/hr)
Condenser Q Energy Stream 282 1.884e+06
Reboiler Q Energy Stream 284 2.211e+06
Table 6: Energy Streams
EXAMPLE 3
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.
33

CA 02949015 2016-11-17
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
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 (MMSCFD) 17.00* 17.00
16.82
Mass Flow (lb/hr) 8.083e+04 8.083e+04 7.968e+04
_
Liquid Volume Flow (USGPM) 203.4 203.4 199.5
Heat Flow (Btu/hr) -3.016e+08 -3.032e+08
-3.025e+08
Table 7A: Material Streams
Purified CO2 Sour NGL Cooled Sour
Name Recycle Rich Stream NGL Rich
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 (MMSCFD) 16.82 0.1763
0.1763
Mass Flow (lb/hr) 7.968e+04 1153 1153
Liquid Volume Flow (USGPM) 199.5 3.894 3.894
Heat Flow (Btu/hr) -3.009e+08 -1.278e+06
-1.340e+06
Table 7B: Material Streams
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
34

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
.,
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 (MMSCFD) 0.1763 0.01048 0.1659
Mass Flow (lb/hr) 1153 48.82 1105
Liquid Volume Flow (USGPM) 3.894 0.1188 3.776
Heat Flow (Btu/hr) -1.340e+06 -1.653e+05
-1.175e+06
Table 7C: Material Streams
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
Stream 160 Stream 252
Stream 258
Comp Mole Frac (H25) 0.0031* 0.0031 0.0030
Comp Mole Frac (Nitrogen) 0.0008* 0.0008 0.0008
Comp Mole Frac (CO2) 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

CA 02949015 2016-11-17
Cooled,
Dehydrated Cooled CO2
Purified CO2
Name CO2 Recycle Recycle
Recycle
Stream 160 Stream 252
Stream 258
Comp Mole Frac (1-120) 0.0000* 0.0000 0.0000
Table 8A: Stream Compositions
36

CA 02949015 2016-11-17
Purified CO2 Sour NGL Cooled Sour
Name Recycle Rich Stream NGL Rich
Stream 164 264 Stream 266
Comp Mole Frac (H2S) 0.0030 0.0094 0.0094
Comp Mole Frac (Nitrogen) 0.0008 0.0000 0.0000
Comp Mole Frac (CO2) 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 (H20) 0.0000 0.0000 0.0000
Table 8B: Stream Compositions
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
Comp Mole Frac (H2S) 0.0094 0.1584 0.0000
Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO2) 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
37

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
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 (H20) 0.0000 0.0000 0.0000
Table 8C: Stream Compositions
Name Heat Flow (Btu/hr)
Condenser Q Energy Stream 282 6.236e+06
Reboiler Q Energy Stream 284 5.666e+06
Table 9: Energy Streams
38

CA 02949015 2016-11-17
EXAMPLE 4
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.
Compressed Purified
Cooled Carbon
Carbon Carbon
Dioxide
Name Dioxide Dioxide
Recycle
Recycle Recycle
Stream 752
Stream 158 Stream 164
Temperature ( 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 (1b/Ibmol) 34.5734 34.5734 33.2372
Molar Flow (lbmol/hr) 143.165 143.165 136.153
Vapor Volumetric Flow (ft3/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/ft3)
Table IOA: Material Streams
39

CA 02949015 2016-11-17
Cooled,
Purified
Dehydrated
Carbon NGL Rich
Name Vapor Recycle
Dioxide Stream 162
Stream 726
Recycle
Stream 758
Temperature ( 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 (1b/Ibmol) 33.2372 33.941 65.1996
Molar Flow (lbmol/hr) 136.153 138.957 5.97957
Vapor Volumetric Flow (ft3/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/f0)
Table 10B: Material Streams
Sour NGL Cooled,
Sour
Aqueous Fluid
Name Rich Stream NGL Rich
Stream 732
764 Stream 766
Temperature ( F) 54.9077 262.193 120

CA 02949015 2016-11-17
Sour NGL Cooled,
Sour
Aqueous Fluid
Name Rich Stream NGL Rich
Stream 732
764 Stream 766
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 (1b/Ibmol) 18.2988 63.2785 63.2785
Molar Flow (Ibmol/hr) 0.354052 6.58207 6.58207
Vapor Volumetric Flow (1t3/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/ft3)
Table 10C: Material Streams
Low-Pressure
Sour NGL
Name Acid Gases 770
Rich Stream
768
Temperature ( 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 (1b/Ibmol) 63.2785 42.366
41

CA 02949015 2016-11-17
Low-Pressure
Sour NGL
Name Acid Gases 770
Rich Stream
768
Molar Flow (lbmol/hr) 6.58207 0.645859
Vapor Volumetric Flow (ft3/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/ft3)
Table IOD: Material Streams
Compressed Purified
Cooled Carbon
Carbon Carbon
Dioxide
Name Dioxide Dioxide
Recycle
Recycle Recycle
Stream 752
Stream 158 Stream 164
Comp Molar Flow H2S (Ibmoi/hr) 0 0 0
Comp Molar Flow Nitrogen 5.42488 5.42488 5.42487
(Ibmoi/hr)
Comp Molar Flow CO2(lbm01Thr) 78.374 78.374 77.7679
Comp Molar Flow Methane 46.8833 46.8833 46.8831
(lbmm/hr)
Comp Molar Flow Ethane (lbmoi/hr) 5.04264 5.04264
4.97376
Comp Molar Flow Propane (lbmm/hr) 2.60218 2.60218
1.06689
Comp Molar Flow i-Butane 0.632167 0.632167 0.0262049
42

CA 02949015 2016-11-17
Compressed Purified
Cooled Carbon
Carbon Carbon
Dioxide
Name Dioxide Dioxide
Recycle
Recycle Recycle
Stream 752
Stream 158 Stream 164
(Ibmcdhr)
Comp Molar Flow n-Butane 1.01441 1.01441 0.0106494
(Ibmm/hr)
Comp Molar Flow i-Pentane 0.543958 0.543958 2.47836E-05
(Ibmoi/hr)
Comp Molar Flow n-Pentane 0.27933 0.27933 6.5645E-06
(lbmoi/hr)
Comp Molar Flow n-Hexane 1.94061 1.94061 6.8325E-08
(lbmoi/hr)
Comp Molar Flow n-Heptane 0 0 0
(lbmoi/hr)
Comp Molar Flow H20 (Ibmolihr) 0.427428 0.427428 1.88221E-05
Comp Molar Flow Diethyle Amine 0 0 0
(lbmm/hr)
Table 11A: Stream Compositions
Cooled,
Purified
Dehydrated
Carbon NGL Rich
Name Vapor Recycle
Dioxide Stream 162
Stream 726
Recycle
Stream 758
Comp Molar Flow H2S (Ibmoi/hr) 0 0 0
Comp Molar Flow Nitrogen 5.42487 5.41324 5.81573E-09
43

CA 02949015 2016-11-17
Cooled,
Purified
Dehydrated
Carbon NGL Rich
Name Vapor Recycle
Dioxide Stream 162
Stream 726
Recycle
Stream 758
(lbmoi/hr)
Comp Molar Flow CO2(lbmol/hr) 77.7679 77.1797 1.75658E-06
Comp Molar Flow Methane 46.8831 46.6143 2.21379E-05
(1b01/hr)
Comp Molar Flow Ethane (lbrnoi/hr) 4.97376 4.89657
0.068452
Comp Molar Flow Propane (lbmcdhr) 1.06689 2.39516
1.53245
Comp Molar Flow i-Butane 0.0262049 0.529946 0.605608
(lbmoiThr)
Comp Molar Flow n-Butane 0.0106494 0.799268 1.00312
(Ibmolihr)
Comp Molar Flow i-Pentane 2.47836E-05 0.345064 0.543843
(lbmoiihr)
Comp Molar Flow n-Pentane 6.5645E-06 0.161123 0.279274
(lbmoi/hr)
Comp Molar Flow n-Hexane 6.8325E-08 0.622204 1.9405
(113,101/hr)
Comp Molar Flow n-Heptane 0 0 0
(1b01/hr)
Comp Molar Flow H20 (1b,õ01/hr) 1.88221E-05 0.000761257
0.0062375
Comp Molar Flow Diethyle Amine 0 0 7.30571E-05
(lbmoi/hr)
Table 11B: Stream Compositions
44

CA 02949015 2016-11-17
Sour NGL Cooled,
Sour
Aqueous Fluid
Name Rich Stream NGL Rich
Stream 732
764 Stream 766
Comp Molar Flow H2S (IbrnoiThr) 0 0 0
Comp Molar Flow Nitrogen 7.93825E-06 5.94147E-09 5.94147E-09
(lbmm/hr)
Comp Molar Flow CO2(lbmoi/hr) 0.00385078 0.602328 0.602328
Comp Molar Flow Methane 0.000125243 2.25954E-05 2.25954E-05
(Ibmoi/hr)
Comp Molar Flow Ethane (lbmm/hr) 1.31496E-05 0.0688655
0.0688655
Comp Molar Flow Propane (Ibmoi/hr) 6.92895E-06 1.53528
1.53528
Comp Molar Flow i-Butane 4.43906E-07 0.605962 0.605962
(Ibmoi/hr)
Comp Molar Flow n-Butane 1.35201E-06 1.00376 1.00376
(lbmoi/hr)
Comp Molar Flow i-Pentane 3.68843E-07 0.543932 0.543932
(Ibmm/hr)
Comp Molar Flow n-Pentane 1.57397E-07 0.279323 0.279323
(Ibmoi/hr)
Comp Molar Flow n-Hexane 1.94686E-07 1.9406 1.9406
(IbmoiThr)
Comp Molar Flow n-Heptane 0 0 0
(Ibmol/hr)
Comp Molar Flow H2O (Ibmoi/hr) 0.350046 0.00199881 0.00199881
Comp Molar Flow Diethyle Amine 0 0 0
(Ibmm/hr)
Table 11C: Stream Compositions

CA 02949015 2016-11-17
Low-Pressure
Sour NGL
Name Acid Gases 770
Rich Stream
768
Comp Molar Flow H2S (lbmoi/hr) 0 0
Comp Molar Flow Nitrogen 5.94147E-09 0
(Ibmoiihr)
Comp Molar Flow CO2(lbm0i/hr) 0.602328 0.602272
Comp Molar Flow Methane 2.25954E-05 2.56258E-07
(lbmol/hr)
Comp Molar Flow Ethane (lbmoiihr) 0.0688655 0.000254578
Comp Molar Flow Propane (lbmoi/hr) 1.53528 0.00159919
Comp Molar Flow i-Butane 0.605962 0.00016306
(lbmoi/hr)
Comp Molar Flow n-Butane 1.00376 0.000353691
(lbmoi/hr)
Comp Molar Flow i-Pentane 0.543932 3.41627E-05
(lbmol/hr)
Comp Molar Flow n-Pentane 0.279323 2.16905E-05
(lbmõi/hr)
Comp Molar Flow n-Hexane 1.9406 4.4341E-05
(lb)1/hr)
Comp Molar Flow n-Heptane 0 0
(lbmoiihr)
Comp Molar Flow H20 (lbmoiThr) 0.00199881 0.0411157
Comp Molar Flow Diethyle Amine 0 4.17895E-20
(lbmoi/hr)
Table 11D: Stream Compositions
46

CA 02949015 2016-11-17
Name Heat Flow (Btu/hr)
Condenser Energy Stream 782 320524
Reboiler Energy Stream 784 253961
Table 12: Energy Streams
EXAMPLE 5
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.
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
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 Flow
46.6598 2.2893 840.0
(barrel/day)
Heat Flow (Btu/hr) -508612 -106053 -7.920e+006
Table 13A: Material Streams
47

CA 02949015 2016-11-17
Overhead Heavy NGL Light NGL
Name
Stream 524 Stream 514 Stream 174
Vapor Fraction 1.0000 0.0000 0.0000
Temperature (F) 185.7 270.6 134.0
Pressure (psig) 160.0 165.0 155.0
Molar Flow (MMSCFD) 0.3687 0.6507 0.3687
Mass Flow (lb/hr) 2186 5381 2186
Standard Liquid Volume Flow
266.4 576.5 266.4
(barrel/day)
Heat Flow (Btu/hr) -2.029e+006 -4.885e+006
-2.367e+006
Table 13B: Material Streams
Cooled, Heavy
Name NGL Stream
172
Vapor Fraction 0.0000
Temperature (F) 100.0
Pressure (psig) 160.0
Molar Flow (MMSCFD) 0.6507
Mass Flow (lb/hr) 5381
Standard Liquid Volume Flow
576.5
(barrel/day)
Heat Flow (Btu/hr) -5.478e+006
Table 13C: Material Streams
48

CA 02949015 2016-11-17
Low-Pressure
Sour NGL Acid Gas NGL Rich
Name
Rich Stream Stream 270 Stream 162
268
Comp Mole Frac (H2S) 0.0000
Comp Mole Frac (Nitrogen) 0.0000
Comp Mole Frac (CO2) 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 (H20) 0.00030 0.06366 0.0000
Table 14A: Stream Compositions
Overhead Heavy NGL Light NGL
Name
Stream 524 Stream 514 Stream 174
Comp Mole Frac (H2S) 0.0000 0.0000 0.0000
Comp Mole Frac (Nitrogen) 0.0000 0.0000 0.0000
Comp Mole Frac (CO2) 0.0000 0.0000 0.0000
Comp Mole Frac (Methane) 0.0000 0.0000 0.0000
Comp Mole Frac (Ethane) 0.0075 0.0000 0.0075
Comp Mole Frac (Propane) 0.4547 0.0013 0.4547
49

CA 02949015 2016-11-17
Overhead Heavy NGL Light NGL
Name
Stream 524 Stream 514 Stream 174
Comp Mole Frac (i-Butane) 0.1330 0.0431 0.1330
Comp Mole Frac (n-Butane) 0.2751 0.2236 0.2751
Comp Mole Frac (i-Pentane) 0.0486 0.1435 0.0486
Comp Mole Frac (n-Pentane) 0.0359 0.1230 0.0359
Comp Mole Frac (n-Hexane) 0.0437 0.4363 0.0437
Comp Mole Frac (n-Heptane) 0.0013 0.0292 0.0013
Comp Mole Frac (n-Octane) 0.0000 0.0000 0.0000
Comp Mole Frac (H20) 0.0000 0.0000 0.0000
Table 14B: Stream Compositions
Cooled, Heavy
Name NGL Stream
172
Comp Mole Frac (H25) 0.0000
Comp Mole Frac (Nitrogen) 0.0000
Comp Mole Frac (CO2) 0.0000
Comp Mole Frac (Methane) 0.0000
Comp Mole Frac (Ethane) 0.0000
Comp Mole Frac (Propane) 0.0013
Comp Mole Frac (i-Butane) 0.0431
Comp Mole Frac (n-Butane) 0.2236
Comp Mole Frac (i-Pentane) 0.1435
Comp Mole Frac (n-Pentane) 0.1230
Comp Mole Frac (n-Hexane) 0.4363
Comp Mole Frac (n-Heptane) 0.0292
Comp Mole Frac (n-Octane) 0.0000
Comp Mole Frac (H20) 0.0000

CA 02949015 2016-11-17
Table 14C: Stream Compositions
Name Heat Flow (Btu/hr)
Reboiler Energy Stream 516 25.4 x 103
Cooling Fluid Stream 522 39.72 x 103
Table 15: Energy Streams
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
Ito 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, RI, and an upper limit, Ru, is disclosed, any number
falling within the
range is specifically disclosed. In particular, the following numbers within
the range are
specifically disclosed: R = R1+ k * - RI), 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
51

CA 02949015 2016-11-17
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.
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.
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.
52

Representative Drawing
A single figure which represents the drawing illustrating the invention.
Administrative Status

For a clearer understanding of the status of the application/patent presented on this page, the site Disclaimer , as well as the definitions for Patent , Administrative Status , Maintenance Fee  and Payment History  should be consulted.

Administrative Status

Title Date
Forecasted Issue Date 2019-09-17
(22) Filed 2011-05-06
(41) Open to Public Inspection 2012-10-28
Examination Requested 2016-11-17
(45) Issued 2019-09-17

Abandonment History

There is no abandonment history.

Maintenance Fee

Last Payment of $263.14 was received on 2023-04-19


 Upcoming maintenance fee amounts

Description Date Amount
Next Payment if small entity fee 2024-05-06 $125.00
Next Payment if standard fee 2024-05-06 $347.00

Note : If the full payment has not been received on or before the date indicated, a further fee may be required which may be one of the following

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Please refer to the CIPO Patent Fees web page to see all current fee amounts.

Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Request for Examination $800.00 2016-11-17
Registration of a document - section 124 $100.00 2016-11-17
Application Fee $400.00 2016-11-17
Maintenance Fee - Application - New Act 2 2013-05-06 $100.00 2016-11-17
Maintenance Fee - Application - New Act 3 2014-05-06 $100.00 2016-11-17
Maintenance Fee - Application - New Act 4 2015-05-06 $100.00 2016-11-17
Maintenance Fee - Application - New Act 5 2016-05-06 $200.00 2016-11-17
Maintenance Fee - Application - New Act 6 2017-05-08 $200.00 2017-04-18
Maintenance Fee - Application - New Act 7 2018-05-07 $200.00 2018-04-24
Maintenance Fee - Application - New Act 8 2019-05-06 $200.00 2019-04-25
Final Fee $300.00 2019-08-07
Maintenance Fee - Patent - New Act 9 2020-05-06 $200.00 2020-04-23
Maintenance Fee - Patent - New Act 10 2021-05-06 $255.00 2021-04-22
Maintenance Fee - Patent - New Act 11 2022-05-06 $254.49 2022-04-21
Maintenance Fee - Patent - New Act 12 2023-05-08 $263.14 2023-04-19
Owners on Record

Note: Records showing the ownership history in alphabetical order.

Current Owners on Record
PILOT ENERGY SOLUTIONS, LLC
Past Owners on Record
None
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.
Documents

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Document
Description 
Date
(yyyy-mm-dd) 
Number of pages   Size of Image (KB) 
Abstract 2016-11-17 1 18
Description 2016-11-17 52 2,149
Claims 2016-11-17 5 175
Drawings 2016-11-17 7 73
Cover Page 2016-12-21 2 46
Examiner Requisition 2017-09-22 4 229
Amendment 2018-03-22 15 378
Claims 2018-03-22 11 284
Examiner Requisition 2018-07-26 3 179
Amendment 2019-01-25 3 144
Final Fee 2019-08-07 3 70
Representative Drawing 2019-08-22 1 7
Cover Page 2019-08-22 1 41
Correspondence 2016-11-30 1 147
New Application 2016-11-17 12 372