U.S. patent application number 11/674984 was filed with the patent office on 2007-06-21 for systems and methods for delivering hydrogen and separation of hydrogen from a carrier medium.
This patent application is currently assigned to Battelle Energy Alliance, LLC. Invention is credited to Dennis N. Bingham, Kerry M. Klingler, Michael G. McKellar, Terry D. Turner, Bruce M. Wilding.
Application Number | 20070137246 11/674984 |
Document ID | / |
Family ID | 39691207 |
Filed Date | 2007-06-21 |
United States Patent
Application |
20070137246 |
Kind Code |
A1 |
McKellar; Michael G. ; et
al. |
June 21, 2007 |
SYSTEMS AND METHODS FOR DELIVERING HYDROGEN AND SEPARATION OF
HYDROGEN FROM A CARRIER MEDIUM
Abstract
Methods and systems are provided for the transportation of
hydrogen including the use of a carrier medium and the subsequent
separation of the hydrogen from the carrier medium upon delivery of
the mixed gas stream to a desired location. In one example, up to
approximately 20% hydrogen (molar fraction) may be mixed with
natural gas and transported through a natural gas pipeline. The
hydrogen may be separated from the natural gas by liquefying the
natural gas and separating the liquid and vapor components in a
gas-liquid separator to form a natural gas stream and a hydrogen
stream. One or both of the separated streams may be used in cooling
of the mixed stream. Precompression and expansion pressure of the
various streams may be used to influence the purity level of the
hydrogen. Other constituents, or impurities, present in the mixed
gas stream may also be removed as may be desired.
Inventors: |
McKellar; Michael G.; (Idaho
Falls, ID) ; Bingham; Dennis N.; (Idaho Falls,
ID) ; Wilding; Bruce M.; (Idaho Falls, ID) ;
Klingler; Kerry M.; (Idaho Falls, ID) ; Turner; Terry
D.; (Idaho Falls, ID) |
Correspondence
Address: |
BATTELLE ENERGY ALLIANCE, LLC
P.O. BOX 1625
IDAHO FALLS
ID
83415-3899
US
|
Assignee: |
Battelle Energy Alliance,
LLC
Idaho Falls
ID
|
Family ID: |
39691207 |
Appl. No.: |
11/674984 |
Filed: |
February 14, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11124589 |
May 5, 2005 |
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11674984 |
Feb 14, 2007 |
|
|
|
10414991 |
Apr 14, 2003 |
6962061 |
|
|
11124589 |
May 5, 2005 |
|
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|
10086066 |
Feb 27, 2002 |
6581409 |
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10414991 |
Apr 14, 2003 |
|
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60288985 |
May 4, 2001 |
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Current U.S.
Class: |
62/620 ;
62/613 |
Current CPC
Class: |
F25J 3/0635 20130101;
F25J 2205/84 20130101; F25J 2220/68 20130101; F25J 2220/62
20130101; F25J 2205/60 20130101; F25J 3/061 20130101; F25J 2220/66
20130101; F25J 3/0655 20130101; F25J 2205/20 20130101 |
Class at
Publication: |
062/620 ;
062/613 |
International
Class: |
F25J 1/00 20060101
F25J001/00; F25J 3/00 20060101 F25J003/00 |
Goverment Interests
GOVERNMENT RIGHTS
[0002] The United States Government has certain rights in this
invention pursuant to Contract No. DE-AC07-05ID14517 between the
United States Department of Energy and Battelle Energy Alliance,
LLC.
Claims
1. A method of transporting hydrogen, the method comprising: adding
a volume of hydrogen to a volume of natural gas to form a mixed gas
volume; flowing the mixed gas volume as a mixed gas stream from a
first location to a second location; cooling the mixed gas stream
and liquefying a substantial portion of the volume of natural gas;
substantially separating the liquefied natural gas from the volume
of hydrogen to provide a natural gas stream and a hydrogen stream;
and using at least one of the natural gas stream and the hydrogen
stream to cool the mixed gas stream.
2. The method according to claim 1, further comprising compressing
the mixed gas stream prior to cooling the mixed gas stream.
3. The method according to claim 2, wherein compressing the mixed
gas stream includes compressing the mixed gas stream to a pressure
of approximately 300 pounds per square inch absolute or
greater.
4. The method according to claim 2, wherein cooling the mixed gas
stream includes flowing the mixed gas stream sequentially through a
first heat exchanger and a second heat exchanger.
5. The method according to claim 4, wherein flowing the mixed gas
stream through the first heat exchanger includes cooling the mixed
gas stream to a temperature of approximately 60.degree. F.
6. The method according to claim 5, wherein flowing the mixed gas
stream through the second heat exchanger includes cooling the mixed
gas stream to a temperature of approximately -265.degree. F.
7. The method according to claim 4, wherein substantially
separating the liquefied natural gas from the volume of hydrogen to
provide a natural gas stream and a hydrogen stream includes flowing
the mixed gas stream from the second heat exchanger into a
gas-liquid separator.
8. The method according to claim 4, wherein using at least one of
the natural gas stream and the hydrogen stream to cool the mixed
gas stream includes expanding at least one of the natural gas
stream and the hydrogen stream and flowing the expanded stream
through the second heat exchanger.
9. The method according to claim 4, wherein using at least one of
the natural gas stream and the hydrogen stream to cool the mixed
gas stream includes expanding the natural gas stream, expanding the
hydrogen stream, and flowing both the expanded natural gas stream
and the expanded hydrogen stream through the second heat
exchanger.
10. The method according to claim 9, further comprising compressing
the expanded natural gas stream.
11. The method according to claim 10, further comprising
compressing the expanded hydrogen stream.
12. The method according to claim 9, further comprising controlling
a purity of the hydrogen stream, at least in part, by selecting the
pressure to which at least one of the hydrogen stream and the
natural gas stream is expanded.
13. The method according to claim 12, further comprising expanding
the at least one of the hydrogen stream and the natural gas stream
to a pressure of approximately 65 pounds per square inch absolute
(psia) or lower.
14. The method according to claim 15, further comprising
controlling a purity of the hydrogen stream, at least in part, by
selecting the pressure to which the mixed gas stream is
compressed.
15. The method according to claim 1, further comprising expanding
at least one of the hydrogen stream and the natural gas stream and
controlling a purity of the hydrogen stream, at least in part, by
selecting the pressure to which the at least one of the hydrogen
stream and the natural gas stream is expanded.
16. The method according to claim 15, further comprising expanding
the at least one of the hydrogen stream and the natural gas stream
to a pressure of approximately 65 pounds per square inch absolute
(psia) or lower.
17. The method according to claim 16, further comprising
compressing the mixed gas stream prior to cooling the mixed gas
stream and controlling a purity of the hydrogen stream, at least in
part, by selecting the pressure to which the mixed gas stream is
compressed.
18. The method according to claim 1, further comprising removing
impurities from the natural gas.
19. The method according to claim 18, wherein removing impurities
from the natural gas further includes removing water from the
natural gas.
20. The method according to claim 19, wherein removing water from
the natural gas includes injecting methanol into the mixed gas
stream, liquefying the water and methanol, and separating the water
and methanol from the mixed gas stream.
21. The method according to claim 18, wherein removing impurities
from the natural gas includes removing carbon dioxide from the
natural gas.
22. The method according to claim 21, wherein removing carbon
dioxide from the natural gas includes producing a slurry of solid
carbon dioxide and natural gas and substantially separating the
solid carbon dioxide from the natural gas.
23. The method according to claim 22, further comprising subliming
the solid carbon dioxide.
24. The method according to claim 1, wherein adding a volume of
hydrogen to a volume of natural gas to provide a mixed gas stream
includes providing a mixed gas stream with up to approximately 20%
molar fraction of hydrogen.
25. A method of separating hydrogen from natural gas contained in a
mixed gas stream, the method comprising: cooling the mixed gas
stream and liquefying a substantial portion of the volume of
natural gas; substantially separating the liquefied natural gas
from the volume of hydrogen to provide a natural gas stream and a
hydrogen stream; and using at least one of the natural gas stream
and the hydrogen stream to cool the mixed gas stream.
26. The method according to claim 25, further comprising
compressing the mixed gas stream prior to cooling the mixed gas
stream.
27. The method according to claim 26, wherein cooling the mixed gas
stream includes flowing the mixed gas stream sequentially through a
first heat exchanger and a second heat exchanger.
28. The method according to claim 27, wherein using at least one of
the natural gas stream and the hydrogen stream to cool the mixed
gas stream includes expanding the natural gas stream, expanding the
hydrogen stream, and flowing both the expanded natural gas stream
and the expanded hydrogen stream through the second heat
exchanger.
29. The method according to claim 28, further comprising
compressing the expanded natural gas stream.
30. The method according to claim 29, further comprising
compressing the expanded hydrogen stream.
31. The method according to claim 28, further comprising
controlling a purity of the hydrogen stream, at least in part, by
selecting the pressure to which at least one of the hydrogen stream
and the natural gas stream is expanded.
32. The method according to claim 31, further comprising expanding
the at least one of the hydrogen stream and the natural gas stream
to a pressure of approximately 65 pounds per square inch absolute
(psia) or lower.
33. The method according to claim 25, further comprising expanding
at least one of the hydrogen stream and the natural gas stream and
controlling a purity of the hydrogen stream, at least in part, by
selecting the pressure to which the at least one of the hydrogen
stream and the natural gas stream is expanded.
34. The method according to claim 25, further comprising
compressing the mixed gas stream prior to cooling the mixed gas
stream and controlling a purity of the hydrogen stream, at least in
part, by selecting the pressure to which the mixed gas stream is
compressed.
35. The method according to claim 25, further comprising removing
impurities from the natural gas.
36. The method according to claim 25, wherein adding a volume of
hydrogen to a volume of natural gas to provide a mixed gas stream
includes providing a mixed gas stream with up to approximately 20%
molar fraction of hydrogen.
37. A system for separating hydrogen from natural gas contained in
a mixed stream, the system comprising: a first compressor; a first
heat exchanger; a second heat exchanger; a gas-liquid separator; at
least one expansion device; a first flow path defined and
configured to deliver a mixed gas stream sequentially through the
first compressor, the second compressor, and into the gas-liquid
separator; and a second flow path defined and configured to deliver
at least one of liquid natural gas and hydrogen gas from the gas
liquid separator, through the at least one expansion device and
through the second heat exchanger.
38. The system of claim 37, wherein the second flow path is defined
and configured to deliver liquid natural gas from the gas liquid
separator, through a first expansion device of the at least one
expansion device and through the second heat exchanger, and wherein
the system further comprises a third flow path defined and
configured to deliver hydrogen from the gas liquid separator,
through a second expansion device of the at least one expansion
device and through the second heat exchanger.
39. The system of claim 38, wherein first and second expansion
devices each include Joule-Thomson valves.
40. The system of claim 38, further comprising a second compressor,
and wherein the second flow path extends from the second heat
exchanger to the second compressor.
41. The system of claim 40, further comprising a third compressor,
and wherein the third flow path extends from the second heat
exchanger to the third compressor.
42. The system of claim 41, further comprising a source of methanol
coupled with the first flow path and configured to introduce a
volume of methanol thereinto.
43. The system of claim 42, further comprising a separating system
coupled with the first flow path and configured to remove water and
methanol from the mixed stream of gas at a location between the
first heat exchanger and the gas-liquid separator.
44. The system of claim 43, further comprising another separating
system coupled with second flow path and configured to remove
carbon dioxide from the liquid natural gas.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application is a continuation-in-part of U.S. patent
application Ser. No. 11/124,589 filed on May 5, 2005, which is a
continuation of U.S. patent application Ser. No. 10/414,991 filed
on Apr. 14, 2003, now U.S. Pat. No. 6,962,061 issued on Nov. 8,
2005, which is a divisional of U.S. patent application Ser. No.
10/086,066 filed on Feb. 27, 2002, now U.S. Pat. No. 6,581,409
issued on Jun. 24, 2003 and which claims the benefit of U.S.
Provisional Patent Application Ser. No. 60/288,985, filed May 4,
2001, the disclosures of which applications are each hereby
incorporated by reference in the entireties.
BACKGROUND OF THE INVENTION
[0003] 1. Field of the Invention
[0004] The present invention relates generally to the
transportation and delivery of gases such as hydrogen and, more
particularly, the transportation and delivery a first gas
intermixed with another gas and the subsequent separation of such
gases at desired levels of purity.
[0005] 2. State of the Art
[0006] Hydrogen is considered a promising energy alternative to
carbon based fuels. Various technologies have been and are still
being developed regarding the production and use of hydrogen as a
fuel or energy source. While many people consider hydrogen to be a
desirable energy alternative to carbon based fuels, often based on
the perceived lack of pollutants in using hydrogen as an energy
source, various obstacles exist in creating a society which relies
in substantial part on hydrogen as opposed to other forms of
energy. Such obstacles generally include the ability to
efficiently, safely and economically produce, transport and store
hydrogen.
[0007] Hydrogen is conventionally transported and delivered by way
of railroad cars, tanker trucks and tanker ships. Such means of
transportation and delivery are generally considered less
economically desirable as compared to transporting other fuels in
the same manner. One reason for this is the energy density of
hydrogen as compared to that of other fuels. For example,
substituting the same volume of gasoline for hydrogen in a tanker
would result in the effective delivery of three times the amount of
energy by the tanker. Considering this from another standpoint, the
net heat of combustion of hydrogen per unit volume has been stated
to be lower than that of methane by a factor of 3.3 or greater.
Thus, hydrogen would have to be compressed at least 3.3 times as
much as methane in order to transport the same energy quantity as
methane for a given volume. Substantial expenses in equipment and
energy would be required (not to mention potential structural
upgrades in transportation equipment) to compress and transport
hydrogen at such elevated pressures.
[0008] A limited amount of hydrogen is currently shipped by
pipelines specifically designed and built for carrying hydrogen.
For example, according to a report by the International Atomic
Energy Agency (IAEA) in May of 1999, a pipeline in the Rhine region
includes approximately 250 kilometers (km) of pipe which delivers
250,000,000 cubic meters per year at a system pressure of 2.2
megaPascals (MPa). According to the same report, 232 km of hydrogen
pipeline is installed near Houston, Texas, delivering hydrogen at a
pressure of 6 MPa. However, as already noted, dedicated hydrogen
pipelines are specifically designed and constructed in accordance
with special issues associated with delivering hydrogen.
[0009] For example, the hydrogen molecule is extremely small and,
therefore, can escape through the lattice of metals. Additionally,
the hydrogen molecule can interact with certain metals, causing the
metals to become brittle. Escaping hydrogen results in
inefficiencies of the delivery system. Embrittlement of the
pipeline clearly poses a threat of structural failure. Thus, in
building hydrogen specific pipelines, more expensive materials
(such as stainless steel) must be used or, alternatively (or in
addition to the use of special materials), the inner surfaces of
the pipelines need to be coated so as to protect the metals and
prevent embrittlement. Additionally, in transporting hydrogen by
pipeline multi-stage compression is likely to be required due to
higher friction losses caused by the compressibility factor
previously mentioned. These factors, coupled with the likely issues
regarding obtaining licenses, permits and satisfying other
regulatory requirements, pose substantial hurdles to building a
comprehensive pipeline dedicated to hydrogen transportation and
delivery.
[0010] Another concept for transporting hydrogen through pipelines
includes injecting the hydrogen into a carrier medium. For example,
the above-referenced IAEA report indicates that hydrogen (H.sub.2)
may be mixed with natural gas in quantities of up to 5% (mole
fraction) of hydrogen and carried in existing natural gas pipelines
without requiring any modifications to the pipeline. Additionally,
the same report indicates that hydrogen may be added to natural gas
in a quantity of up to 20% (mole fraction) and carried in existing
pipelines with relatively minimal modifications of such pipelines.
However, in order for such a transportation and delivery option to
be feasible, separation of the hydrogen from the natural gas, or
other carrier medium, in desired levels of purity will be required.
Existing facilities that might be used for separating natural gas
and hydrogen are large scale with footprints measured in acres and
with estimated capital costs ranging from $50 million to $3
billion. Smaller scale, "appliance" size plants for separating
natural gas and hydrogen are not currently known to be available in
the market.
[0011] With hydrogen being a focus for the energy needs of the
future, the economical transportation of large volumes of hydrogen
will be required. It would be desirable to provide a more efficient
method and system of transporting hydrogen. It would also be
desirable to provide a method and system of transporting hydrogen
that utilizes existing infrastructure and, perhaps, avoids many of
the regulatory issues that would be encountered in implementing new
infrastructure. Further, it would be desirable to provide systems
and methods for separating hydrogen from a carrier medium at
desired purity levels to take advantage of potential pipeline
distribution of hydrogen.
BRIEF SUMMARY OF THE INVENTION
[0012] In accordance with one embodiment of the present invention,
a method is provided for separating hydrogen from natural gas, both
of which are contained in a mixed gas stream. The method includes
cooling the mixed gas stream and liquefying a substantial portion
of the volume of natural gas. The liquefied natural gas is
substantially separated from the volume of hydrogen to provide a
natural gas stream and a hydrogen stream. At least one of the
natural gas stream and the hydrogen stream are used to cool the
mixed gas stream. In one embodiment, both the natural gas stream
and the hydrogen gas stream are used to cool the mixed gas stream.
The desired purity level of the resulting hydrogen stream may be
altered by compressing the incoming mixed gas stream, adjusting the
pressure to which the gas stream is expanded, or by both
actions.
[0013] In accordance with another embodiment of the present
invention, a method is provided for transporting hydrogen. The
method includes adding a volume of hydrogen to a volume of natural
gas to provide a mixed gas stream. The mixed gas stream is flowed
from a first location to a second location and then cooled. A
substantial portion of the volume of natural gas is liquefied and
the liquefied natural gas is separated from the volume of hydrogen
to provide a natural gas stream and a hydrogen stream. At least one
of the natural gas stream and the hydrogen stream is used to cool
the mixed gas stream. In one embodiment, both the natural gas
stream and the hydrogen gas stream are used to cool the mixed gas
stream. The desired purity level of the resulting hydrogen stream
may be altered by compressing the incoming mixed gas stream,
adjusting the pressure to which the gas stream is expanded, or by
both actions.
[0014] In accordance with another embodiment of the present
invention, a system is provided for separating hydrogen from
natural gas. The system includes a first compressor, a first heat
exchanger, a second heat exchanger, a gas-liquid separator and at
least one expansion device. The system further includes a first
flow path that is defined and configured to deliver a mixed gas
stream sequentially through the first compressor, the second
compressor, and into the gas-liquid separator. The system
additionally includes a second flow path that is defined and
configured to deliver at least one of liquid natural gas and
hydrogen gas from the gas liquid separator, through the at least
one expansion device and through the second heat exchanger. In
other embodiments, the system may include additional or different
components.
[0015] Other methods and systems are also provided in accordance
with various embodiments of the present invention as will be
appreciated upon a reading of the detailed description of the
various embodiments of the present invention.
BRIEF DESCRIPTION OF THE SEVERAL VIEWS OF THE DRAWINGS
[0016] The foregoing and other advantages of the invention will
become apparent upon reading the following detailed description and
upon reference to the drawings in which:
[0017] FIG. 1 is a process diagram of one embodiment of a system
and process for separating hydrogen from a carrier medium;
[0018] FIG. 2 is a chart showing purity levels of hydrogen based on
inlet and outlet pressures;
[0019] FIG. 3 is a process diagram of another embodiment of a
system and process for separating hydrogen from a carrier
medium;
[0020] FIG. 4 is a table listing various characteristics of fluids
at certain locations within the system shown in FIG. 1 in
accordance with an embodiment of the present invention; and
[0021] FIG. 5 is a table listing the gas compositions at various
locations within the system shown in FIG. 1 in accordance with an
embodiment of the present invention.
DETAILED DESCRIPTION OF THE INVENTION
[0022] Referring to FIG. 1, a system 100 is shown for separating a
desired gas from a carrier medium. While the present embodiment is
set forth in terms of separating hydrogen from natural gas, it is
noted that the present invention may be practiced using various
other types of gases and carrier mediums.
[0023] The system 100 includes a separating plant 102 which is
coupled to a source of gas such as, for example, a pipeline 104. In
one example, the gas stream may be flowing through the pipeline 104
which includes approximately 80% natural gas (e.g., approximately
95% methane, approximately 2% ethane, approximately 2% nitrogen and
approximately 1% propane) and approximately 20% hydrogen
(percentages in molar fractions). An incoming stream of gas 106
from the natural gas/hydrogen stream in the pipeline 104 may be
drawn into the plant 102 through an inlet 108 at, for example, a
pressure of approximately 100 pounds per square inch absolute
(psia) to approximately 500 psia depending on the pressure of the
stream in the pipeline 104. If desired, the pressure of the
incoming stream 106 may be flowed through a compressor 110 to raise
the pressure to a desired level. For example, the incoming stream
106 may be compressed to raise the pressure to between, for
example, approximately 300 psia and approximately 500 psia. As will
be discussed in further detail hereinbelow, an increase in the
pressure of the gas stream at the inlet 106 of the plant 102 may
result in increased purity of the hydrogen that is separated from
the natural gas or other carrier medium.
[0024] If the incoming stream does pass through the compressor 110,
heat energy will be added to the stream. To remove the added heat
energy, or at least a portion thereof, the compressed gas stream
112 may be flowed through a heat exchanger 114. The heat exchanger
114 may use ambient conditions, such as, for example, air, water,
or ground temperature, or a combination thereof, for cooling the
compressed gas stream 112. In one example, an ambient heat
exchanger 114 may be designed to process the compressed gas stream
112 at approximately 4500 to 4600 lbs mass per hour (lbn/hr) at a
design pressure of approximately 500 psia. In one embodiment, the
heat exchanger 114 may further be configured such that the inlet
temperature of the gas is approximately 149.degree. F. and the
outlet temperature of the gas is approximately 59.degree. F. The
heat exchanger 114 may be provided with a fan that is driven, for
example, by a suitable electric motor.
[0025] The compressed gas stream 112 may then enter a first side,
or a warm side, of a high efficiency heat exchanger 116 where, if
desired, the compressed gas stream 112 may be cooled to cryogenic
temperatures such that the natural gas becomes liquefied. For
example, the compressed gas stream may be cooled to temperatures
below approximately -200.degree. F. In one embodiment, the high
efficiency heat exchanger 116 may be configured as a countercurrent
flow, plate and fin type heat exchanger. Additionally, the plates
and fins may be formed of a highly thermally conductive material
such as, for example, aluminum. The high efficiency heat exchanger
116 is positioned and configured to efficiently transfer as much
heat as possible from the compressed gas stream 112 to the cooling
streams that are discussed in further detail below. The high
efficiency heat exchanger 116 may be configured, in one example,
such that the inlet temperature of the gas will be approximately
59.degree. F. and the outlet temperature of the gas will be
approximately -265.degree. F.
[0026] The cooled stream 117 flows from the high efficiency heat
exchanger 116 to a gas-liquid separator 118. The separator may
include a pressure vessel configured to withstand a desired
pressure. For example, the separator 118 may be maintained at a
pressure of approximately 500 psia. The hydrogen vapor and liquid
natural gas (LNG) are separated in the gas-liquid separator 118. A
hydrogen stream 120 flows from an upper portion of the separator
118 through appropriate piping. An LNG stream 122 flows from a
lower portion of the separator 118 through appropriate piping. The
hydrogen stream 120 and the LNG stream 122 each flow through
associated expansion valves 124 and 126, respectively, causing each
of the associated streams to expand to pressures of, for example,
between approximately 1 psia and approximately 65 psia and cool to
temperatures of, for example, between approximately -270.degree. F.
and approximately -280.degree. F. The expansion valves 124 and 126
may include Joule-Thomson (JT) valves which operate on the
principle that expansion of gas will result in an associated
cooling of the gas as well, as is understood by those of ordinary
skill in the art. Of course other expansion devices may be used in
place of the expansion valves 124 and 126 if desired.
[0027] After flowing through their associated expansion valves 124
and 126, the hydrogen stream 120 and LNG stream 122 enter the
second, or cold, side of the high efficiency heat exchanger 116
providing cooling to the compressed gas stream 112. In one example,
the temperature of the hydrogen stream 120 and the LNG stream 122
may be raised to between approximately 15.degree. F. and 40.degree.
F. as it passes through the heat exchanger 116. It is noted that
the LNG stream 122 returns to a gaseous state after passing
sequentially through the expansion valve 126 and the heat exchanger
116. The hydrogen stream 120 may then flow through a compressor
130, if desired, to raise its pressure to, for example
approximately 65 psia at a temperature of approximately 355.degree.
F. before flowing through a plant outlet 132 to be collected for
storage, further processing or use, for example, as a fuel.
Similarly, the natural gas stream (now indicated by reference
numeral 134 based on its state change) may flow through a
compressor 136, if desired, to raise its pressure to, for example,
approximately 65 psia at a temperature of approximately 294.degree.
F. before flowing through a plant outlet 138 to be collected for
storage, further processing or use, for example, as a fuel. In one
example, the natural gas may be returned to the pipeline 104 from
which it was taken, downstream from the location where it was
originally removed from the pipeline 104. It is noted that, if the
pressures in the hydrogen stream 120 and the natural gas stream 134
are below atmospheric pressures as they exit the heat exchanger
116, vacuum pumps (not shown) may be coupled to the hydrogen and
natural gas streams 120 and 134 in order to obtain proper operation
of the plant 102. While the use of vacuum pumps would add cost to
the overall cost of the system 100, operation at such low pressures
would result in extremely pure hydrogen (e.g., purity levels of
approximately 99% or higher) at the outlet 132.
[0028] Referring briefly to FIG. 2, a three-dimensional plot
depicts the impact of the inlet pressure (i.e. the pressure of the
incoming stream of gas 106 or the pressure to which the incoming
stream is compressed by compressor 110) and the pressure to which
the gas stream or streams are expanded (i.e., the pressure of the
hydrogen stream 120 after flowing through the expansion valve 124
and the pressure of the natural gas stream 122 after flowing
through the expansion valve 126) on the resulting purity of the
hydrogen. Generally, at relatively high expansion pressures, the
hydrogen purity tends to be low. However, the level of hydrogen
purity rises as the inlet pressure rises. At low expansion
pressures the purity of hydrogen is generally above 95% and the
inlet pressure has relatively little effect on the level of
hydrogen purity. As seen in FIG. 2, if inlet pressures are high
enough (e.g., approximately 300 psia or higher) the level of
hydrogen purity is above 90% even for expansion pressures that are
in the range of approximately 55 psia. Thus, controlling the inlet
pressures and expansion pressure of the plant, such as by using
precompression (i.e., with compressor 110) and various expansion
devices, also controls the purity level of the hydrogen separated
from the natural gas.
[0029] It is also noted that the level of other constituents
present within the gas stream (i.e., prior to entering the plant
inlet 108) may also have an impact on the purity level of hydrogen
obtained from the separation process. For example, it has been
determined that as the nitrogen level increases, as measured at the
inlet 108, the purity of the hydrogen decreases at the outlet 132.
It is believed that this is because the nitrogen does not liquefy
with the natural gas and, therefore, is withdrawn with the hydrogen
from the gas-liquid separator 118. Additionally, it is noted that
the amount of methane at the outlet 132 (in the hydrogen stream
120) decreases with such an increase of nitrogen.
[0030] Depending on the intended use of the hydrogen, the existence
of either nitrogen or methane in certain quantities may have an
undesirable effect on the performance of the hydrogen in its final
use. For example, if the hydrogen is used in a fuel cell, the
methane can mix with oxygen to form carbon monoxide and carbon
dioxide, which can block the access of hydrogen to the fuel cell's
catalyst sites. On the other hand, the presence of nitrogen may
adversely affect the performance of a fuel cell by forming a
nitrogen blanket around the cathode. Thus, depending on the
intended use of the hydrogen, the composition of the incoming
stream of gas 106 may need to be taken into account as another
factor in adjusting inlet and outlet pressures and controlling the
purity level of the hydrogen.
[0031] Consideration may also need to be given to the potential of
impurities (e.g., carbon dioxide and water) present in the natural
gas of the incoming stream 106. It is generally noted that
impurities such as carbon dioxide and water will become solids at
the cryogenic temperatures that exist in the plant 102. Solid
carbon dioxide or water could build up and block the passages
within one of the heat exchangers (e.g., heat exchanger 116), the
valves 124 and 126 (or other expansion devices) or any of the
associate piping or separator. Various options may be used to deal
with such potential solid-forming impurities.
[0032] For example, in one embodiment, an amine scrubber system may
be used wherein an amine solution captures the impurities from the
incoming stream of gas 106 by way of a pack column. The impurities
may be subsequently separated from the amine solution by way of
energy input such that the amine solution may be recycled and
reused.
[0033] In another embodiment, a ceramic palladium membrane system
may be used to remove the impurities from the incoming stream of
gas 106. The ceramic membrane allows the hydrogen molecule
(H.sub.2) to pass through while preventing the passage of larger
molecules contained in the natural gas. While such a system would
likely be costly, purity levels of hydrogen approaching 100% could
conceivably be obtained.
[0034] In yet another embodiment, water management and carbon
dioxide management systems may be used, including configurations
similar to those described in U.S. Pat. No. 6,581,409 entitled
APPARATUS FOR THE LIQUEFACTION OF NATURAL GAS AND METHODS RELATING
TO SAME, the disclosure of which is incorporated by reference
herein in its entirety.
[0035] For example, with reference to FIG. 3, a plant 102' may be
configured generally similar to the plant 102 described with
respect to FIG. 1, but with some modifications to accommodate the
implementation of a water management system 150, a carbon dioxide
management system 152 or both. In such an embodiment, methanol, or
some other water absorbing material, may be injected into the
incoming stream of gas 106 to enable the removal of water from the
natural gas stream during the processing of the incoming stream of
gas 106 and for prevention of ice formation throughout the plant
102'. In connection with the water management system 150, a source
of methanol 160, or some other water absorbing product, may be
injected into the gas stream, via a pump 162, at a location prior
to the gas being passed through the high efficiency heat exchanger
116. The pump 162 may include variable flow capability to inject
methanol into the gas stream by way of, for example, an atomizing
or a vaporizing nozzle. Alternatively, valving may be used to
accommodate multiple types of nozzles such that an appropriate
nozzle may be used depending on the flow characteristics of the
incoming stream of gas 106.
[0036] A suitable pump 162 for injecting the methanol may include
variable flow control in the range of 0.4 to 2.5 gallons per minute
(GPM) at a design pressure of approximately 1000 psia for a water
content of approximately 2 to 7 pounds mass per millions of
standard cubic feet (lbm/mmscf). The variable flow control may be
accomplished through the use of a variable frequency drive coupled
to a motor of the pump 162. One such pump is available from America
LEWA located in Holliston, Mass.
[0037] The methanol is mixed with the incoming stream of gas 106 to
lower the freezing point of any water which may be contained
therein. The methanol mixes with the incoming stream of gas 106 and
binds with the water to prevent the formation of ice. Part way
through the heat exchange process in the high efficiency heat
exchanger 116 (e.g., at temperatures between approximately
-60.degree. F. and -90 F) the methanol and water form a liquid. The
compressed gas stream 112 is temporarily diverted from the heat
exchanger 116 and passed through a water management 150 system
which, in one embodiment may include a separating tank wherein the
methanol/water liquid is separated from the compressed gas stream
112. The liquid may then be discharged from the separator tank and
the gas may flow, for example, through a coalescing filter to
remove an additional amount of the methanol/water mixture. The
methanol/water mixture may be discharged from the coalescing filter
through appropriate piping and the dried gas may then reenter the
heat exchanger 116 for further cooling and processing.
[0038] Additionally, the plant 102' may include other systems to
handle other impurities such as a carbon dioxide management system
152. In one example of such a system, instead of reducing the
temperature of the compressed gas stream 112 within the heat
exchanger 116 to a temperature that would result in the production
of solid carbon dioxide and potential blockage of the heat
exchanger 116, the heat exchanger 116 may be used to lower the
temperature of the compressed gas stream to a temperature slightly
above the temperature at which carbon dioxide becomes a solid
(e.g., from approximately -185.degree. F. to -195.degree. F.). Just
prior to entry into the gas liquid separator 118, the cooled gas
stream 117 may pass through an expansion device 166, such as a JT
valve, to expand the gas and lower the temperature of the gas
stream to a level such that LNG and solid carbon dioxide are
produced within the gas-liquid separator 118. The hydrogen may be
removed from the gas-liquid separator 118 as discussed previously
with respect to the plant described in FIG. 1.
[0039] The slurry of solid carbon dioxide and LNG may be removed
from the gas-liquid separator 118 to separate the carbon dioxide
from the LNG, if desired, using a carbon dioxide separation system
152 which may include the use of hydrocyclones, filters or both
(such as detailed in U.S. Pat. No. 6,581,409). The LNG may be
processed and used for cooling in the heat exchanger 116 as
previously described herein. The solid carbon dioxide may be
passed, for example, to a sublimation tank 170 where the carbon
dioxide returns to a gaseous state in a manner similar to that
which is described in U.S. Pat. No. 6,581,409. The gaseous carbon
dioxide may then be passed through heat exchanger 116 to provide
additional cooling, returned directly to the pipeline 104, or
otherwise processed or disposed of as desired as generally
indicated on FIG. 3 by dashed lines.
[0040] The system and process shown in FIG. 3 thus provides for
efficient separation of hydrogen form a carrier medium, such as
natural gas, while integrating processes to remove impurities such
as water or carbon dioxide without expensive equipment and
preprocessing.
[0041] It is noted that implementation of such a carbon dioxide
management system 152 may require further compression of the
incoming stream of gas 106 to accommodate the expansion activity
taking place before the entrance of the cooled stream into the
gas-liquid separator 118.
[0042] Various control schemes may be used to operate the plants
102 and 102'. Also, additional piping, valving and other process
equipment may be utilized such as described in the various
documents incorporated by reference herein and as will be
appreciated by those of ordinary skill in the art.
EXAMPLE
[0043] The system 100 described with respect to FIG. 1 was modeled
to determine the characteristics of the fluid within the system 100
at specific state points for separation of hydrogen from natural
gas in a mixed stream having 20% hydrogen and 80% natural gas
(molar fractions). FIG. 4 is a table setting forth such state point
characteristics. The locations of state points are identified on
FIG. 1 wherein state point 200 is at the inlet 108 of the plant
102. State point 202 refers to the compressed gas stream 112 at a
location after the compressor 110 and prior to the ambient heat
exchanger 114. State point 204 refers to the compressed gas stream
112 at a location between the two heat exchangers 114 and 116.
State point 206 refers to the cooled stream 117 at a location
between the heat exchanger 116 and the separator 118. State point
208 refers to the hydrogen stream 120 as it leaves the gas-liquid
separator 118. State point 210 refers to the hydrogen stream 120 at
a location between the expansion valve 124 and the heat exchanger
116. State point 212 refers to the hydrogen stream 120 at a
location between the heat exchanger 116 and the compressor 130.
State point 214 refers to the hydrogen stream at a location after
it passes through the compressor 130.
[0044] State point 216 refers to the LNG stream 122 as it leaves
the gas-liquid separator 118. State point 218 refers to the LNG
stream 122 at a location between the expansion valve 126 and the
heat exchanger 116. State point 220 refers to the natural gas
stream 134 at a location between the heat exchanger 116 and the
compressor 136. And state point 222 refers to the natural gas
stream 134 after it leaves the compressor 136.
[0045] FIG. 5 further shows the composition of various gas streams
at identified state points. The compositions are set forth in molar
fractions of the identified constituents.
[0046] It is noted that, for the purposes of the model described
with respect to FIGS. 1, 4 and 5, that the power input for the
compressor 110 will be approximately 153 kiloWatts (kW), the power
input for the natural gas compressor 136 will be approximately 395
kW, and the power input for the hydrogen compressor 130 will be
approximately 98 kW.
[0047] Thus, various embodiments of the invention provide systems
and methods for transporting, delivering and separating hydrogen
and a carrier medium, such as natural gas, with the mixture
containing up to approximately 20% hydrogen while obtaining purity
levels of the separated hydrogen from, for example, approximately
80% to approximately 99%. Such capability will enable the use of
existing pipelines for the transport and delivery of hydrogen
without major modifications to such pipelines which would require
substantial time and capital investment.
[0048] While the invention may be susceptible to various
modifications and alternative forms, specific embodiments have been
shown by way of example in the drawings and have been described in
detail herein. However, it should be understood that the invention
is not intended to be limited to the particular forms disclosed.
Rather, the invention includes all modifications, equivalents, and
alternatives falling within the spirit and scope of the invention
as defined by the following appended claims.
* * * * *