U.S. patent application number 13/145972 was filed with the patent office on 2011-12-08 for methods and systems of regenerative heat exchange.
Invention is credited to Mark E. Ehrhardt, Bruce T. Kelley, William S. Mathews, Moses Minta, Eric D. Nelson.
Application Number | 20110297346 13/145972 |
Document ID | / |
Family ID | 42562015 |
Filed Date | 2011-12-08 |
United States Patent
Application |
20110297346 |
Kind Code |
A1 |
Minta; Moses ; et
al. |
December 8, 2011 |
Methods and Systems of Regenerative Heat Exchange
Abstract
The present disclosure teaches apparatuses, systems, and methods
for improving energy efficiency using high heat capacity materials.
Some embodiments include a phase change material (PCMs).
Particularly, the systems may include a re-gasification system, a
liquefaction system, or an integrated system utilizing a heat
exchanger with a regenerator matrix, a shell and tube arrangement,
or cross-flow channels (e.g. a plate-fin arrangement) to store cold
energy from a liquefied gas in a re-gasification system at a first
location for use in a liquefaction process at a second location.
The regenerator matrix may include a plurality of PCMs stacked
sequentially or may include a continuous phase material comprised
of multiple PCMs. Various encapsulation approaches may be utilized.
Reliquefaction may be accomplished with such a system. Natural gas
in remote locations may be made commercially viable by converting
it to liquefied natural gas (LNG), transporting, and delivering it
utilizing the disclosed systems and methods.
Inventors: |
Minta; Moses; (Missouri
City, TX) ; Kelley; Bruce T.; (Kingwood, TX) ;
Mathews; William S.; (The Woodlands, TX) ; Nelson;
Eric D.; (Houston, TX) ; Ehrhardt; Mark E.;
(Houston, TX) |
Family ID: |
42562015 |
Appl. No.: |
13/145972 |
Filed: |
December 15, 2009 |
PCT Filed: |
December 15, 2009 |
PCT NO: |
PCT/US09/68083 |
371 Date: |
July 22, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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61161683 |
Mar 19, 2009 |
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61151765 |
Feb 11, 2009 |
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Current U.S.
Class: |
165/10 ;
165/164 |
Current CPC
Class: |
F17C 2260/016 20130101;
F17C 2270/0121 20130101; F17C 2265/015 20130101; F17C 2227/015
20130101; F17C 2270/0105 20130101; F25J 2205/24 20130101; Y02E
60/147 20130101; F17C 2225/0123 20130101; F25J 1/0277 20130101;
F17C 2201/0157 20130101; F17C 2201/0185 20130101; F17C 2250/043
20130101; Y02E 60/145 20130101; F17C 2221/032 20130101; F28D 7/16
20130101; F28D 17/02 20130101; Y02E 60/14 20130101; Y02E 60/321
20130101; F17C 2221/012 20130101; F17C 2225/0161 20130101; F25J
1/0022 20130101; F25J 5/00 20130101; F17C 2225/033 20130101; F17C
2227/0362 20130101; F17C 2227/0397 20130101; F17C 2260/046
20130101; F25J 1/0035 20130101; F25J 1/0278 20130101; F17C
2201/0128 20130101; F17C 2203/0607 20130101; F17C 2265/05 20130101;
F25J 1/0025 20130101; F17C 2221/011 20130101; F17C 2227/0157
20130101; F25J 2230/30 20130101; F17C 2221/031 20130101; F25J
1/0262 20130101; F28D 9/0062 20130101; F17C 2221/013 20130101; C09K
5/063 20130101; Y02P 20/124 20151101; Y02E 60/32 20130101; F17C
2223/0123 20130101; F17C 2227/0365 20130101; F17C 2227/0142
20130101; Y02P 20/10 20151101; F17C 2265/034 20130101; F28D 20/023
20130101; F17C 2223/033 20130101; F25J 2235/60 20130101; F17C
2250/0439 20130101; F17C 2227/033 20130101; F25J 1/0042 20130101;
F28D 20/02 20130101; F17C 2221/033 20130101; F17C 2250/032
20130101; F17C 9/02 20130101; F25J 1/0251 20130101; F17C 2221/014
20130101; F17C 2221/035 20130101; F17C 2223/0161 20130101; F17C
2227/0304 20130101; F17C 2260/053 20130101 |
Class at
Publication: |
165/10 ;
165/164 |
International
Class: |
F28D 19/00 20060101
F28D019/00 |
Claims
1. A heat transfer system, comprising: a regasification system at a
first location configured to convert a first volume of liquefied
gas (LG) contained at or below a liquefaction temperature into a
first volume of gas at above the liquefaction temperature, the
regasification system comprising a heat exchange apparatus,
comprising: a regenerator matrix including a volume of high heat
capacity materials configured to recover and store cold energy from
the LG from the regasification system for subsequent use at a
second location to provide at least a portion of a cold energy
requirement for liquefaction of a second volume of gas into a
second volume of LG.
2. A heat transfer system, comprising: a liquefaction system at a
first location configured to convert a first volume of gas at above
a liquefaction temperature into a first volume of liquefied gas
(LG) contained at or below the liquefaction temperature, the
liquefaction system comprising a heat exchange apparatus,
comprising: a regenerator matrix including a volume of high heat
capacity materials configured to provide cold energy to the first
volume of gas in the liquefaction system, wherein the cold energy
is obtained from a regasification system at a second location
configured to regasify a second volume of LG contained at
liquefaction temperatures.
3. A heat transfer system, comprising: a heat exchange apparatus,
comprising: a regenerator matrix including a volume of high heat
capacity materials, wherein the regenerator matrix is configured
to: a) recover and store cold energy from a volume of liquefied gas
at or below a liquefaction temperature from a regasification system
at a first location; and b) provide cold energy to a volume of gas
at above the liquefaction temperature in a liquefaction system at a
second location.
4. The system of any one of claims 1-3, wherein the heat exchange
apparatus is mounted to a liquefied natural gas (LNG) carrier and
the liquefied gas (LG) is LNG.
5. The system of any one of claims 1-3, wherein the volume of high
heat capacity materials includes a phase-change material (PCM).
6. The system of claim 5, wherein the regenerator matrix comprises
a series of phase-change materials (PCMs) stacked sequentially
based on a phase transition temperature of the PCMs.
7. The system of claim 5, wherein the regenerator matrix comprises
a thermo-adjustable mixture of at least two phase-change materials
(PCMs) which allow a phase transition temperature to be tuned based
on the composition of the mixture, wherein each PCM has a different
phase transition temperature.
8. The system of any one of claims 1-3, wherein the high heat
capacity material is a single composite material configured to span
a range of temperatures including the liquefaction temperature.
9. The system of any one of claims 1-3, wherein the regenerator
matrix is configured to utilize the stored cold energy to
re-liquefy a volume of boil-off gas between the first location and
the second location.
10. The system of claim 5, wherein the regenerator matrix is in a
form selected from the group consisting of: micro-encapsulated
spheroids, micro-encapsulated sheets, macro-encapsulated spheroids,
macro-encapsulated sheets, a micro-encapsulated honey-comb network,
a macro-encapsulated honey-comb network, and a finned heat exchange
element.
11. A method of delivering liquefied natural gas (LNG), comprising:
flowing LNG to a heat exchange apparatus from an LNG storage tank
on an LNG carrier at an LNG gasification location; recovering cold
energy from the LNG using the heat exchange apparatus having a
regenerator matrix including a volume of high heat capacity
materials to form at least partially vaporized natural gas; storing
the cold energy in the high heat capacity materials for use at an
LNG liquefaction location; and delivering the at least partially
vaporized natural gas to a consuming market.
12. A method of producing natural gas, comprising: feeding a
natural gas stream to a heat exchange apparatus on a liquefied
natural gas (LNG) carrier from a producing location; passing the
natural gas stream through the heat exchange apparatus having a
regenerator matrix including a volume of high heat capacity
materials, comprising: a) imparting cold energy from the high heat
capacity materials to the natural gas to form at least partially
liquefied natural gas; and b) storing heat energy in the high heat
capacity materials for use at an LNG gasification location; and
storing the at least partially liquefied natural gas on the LNG
carrier.
13. The method of claim 11, further comprising pressurizing the
liquefied natural gas (LNG) prior to passing the LNG to the heat
exchange apparatus.
14. The method of claim 11, further comprising adding supplemental
heat to the at least partially vaporized natural gas to form
substantially vaporized natural gas at about an ambient temperature
or about a delivery temperature.
15. The method of any one of claims 11-12, wherein the volume of
high heat capacity materials includes a phase-change material
(PCM).
16. The method of any one of claims 11-12, wherein the regenerator
matrix is in a form selected from the group consisting of:
micro-encapsulated spheroids, micro-encapsulated sheets,
macro-encapsulated spheroids, macro-encapsulated sheets, a
micro-encapsulated honey-comb network, a macro-encapsulated
honey-comb network, and a finned heat exchange element.
17. The method of claim 15, wherein the regenerator matrix
comprises a series of phase-change materials (PCMs) stacked
sequentially based on a phase transition temperature of the
PCMs.
18. The method of claim 15, wherein the regenerator matrix
comprises a thermo-adjustable mixture of at least two phase-change
materials (PCMs) which allow a phase transition temperature to be
tuned based on the composition of the mixture, wherein each PCM has
a different phase transition temperature.
19. The method of any one of claims 11-12, wherein the regenerator
matrix is configured to utilize the stored cold energy to
re-liquefy a volume of boil-off gas between the liquefaction
location and the gasification location.
20. The method of claim 12, further comprising pre-cooling the
natural gas feed stream prior to passing the natural gas stream to
the heat exchange apparatus.
21. The method of claim 12, further comprising adding supplemental
cooling to the at least partially liquefied natural gas to form
substantially liquefied natural gas.
22. A heat transfer system, comprising: a regasification system at
a first location configured to convert a first volume of liquefied
gas (LG) contained at or below a liquefaction temperature into a
first volume of gas at above the liquefaction temperature, the
regasification system comprising a heat exchange apparatus,
comprising: a shell and tube heat exchanger comprising: a) a sealed
tube bundle containing a volume of high heat capacity material; and
b) the shell side is configured to receive the first volume of
liquefied gas (LG) to provide the cold energy to the volume of high
heat capacity material in the sealed tube bundle, wherein the
volume of high heat capacity material is configured to recover and
store cold energy from the LG from the regasification system for
subsequent use at a second location to provide at least a portion
of a cold energy requirement for liquefaction of a second volume of
gas into a second volume of LG.
23. A heat transfer system, comprising: a liquefaction system at a
first location configured to convert a first volume of gas at above
a liquefaction temperature into a first volume of liquefied gas
(LG) contained at or below the liquefaction temperature, the
liquefaction system comprising a heat exchange apparatus,
comprising: a shell and tube heat exchanger, comprising: a) a
sealed tubes bundle containing a volume of high heat capacity
material configured to store cold energy; and b) the shell side is
configured to receive the first volume of gas to receive at least a
portion of the stored cold energy, wherein the volume of high heat
capacity material is further configured to provide cold energy to
the first volume of gas in the liquefaction system, wherein the
cold energy is obtained from a regasification system at a second
location configured to regasify a second volume of LG contained at
liquefaction temperatures.
24. The system of any one of claims 22-23, wherein each sealed tube
in the sealed tube bundle containing the volume of high heat
capacity material also is also filled with a non-condensible
gas.
25. The system of claim 24, wherein the sealed tubes in the sealed
tube bundle containing the volume of high heat capacity material
are provided with a non-condensible gas through a connected buffer
volume.
26. The system of any one of claims 24-25, wherein the volume of
high heat capacity materials includes a phase-change material (PCM)
configured to utilize at least the latent heat of vaporization.
27. A method of delivering liquefied natural gas (LNG), comprising:
flowing LNG to a heat exchange apparatus from an LNG storage tank
on an LNG carrier at an LNG gasification location; recovering cold
energy from the LNG utilizing the heat exchange apparatus having a
shell and tube heat exchanger including sealed tubes containing a
volume of high heat capacity material to form at least partially
vaporized natural gas; storing the cold energy in the high heat
capacity materials for use at an LNG liquefaction location; and
delivering the at least partially vaporized natural gas to a
consuming market.
28. The system of claim 27, wherein each sealed tube containing the
volume of high heat capacity material also is also filled with a
non-condensible gas
29. The system of claim 27, wherein the sealed tube containing the
volume of high heat capacity material are provided with a
non-condensible gas through a connected buffer volume.
30. The system of any one of claims 28-29, wherein the volume of
high heat capacity materials includes a phase-change material (PCM)
configured to utilize at least the latent heat of vaporization.
31. A heat transfer system, comprising: a regasification system at
a first location configured to convert a first volume of liquefied
gas (LG) contained at or below a liquefaction temperature into a
first volume of gas at above the liquefaction temperature, the
regasification system comprising a heat exchange apparatus,
comprising: a cross-flow heat exchanger comprising: a) at least one
plugged flow channel containing a volume of high heat capacity
material; and b) at least one open flow channel configured to
receive the first volume of liquefied gas (LG) to provide cold
energy to the volume of high heat capacity material in the at least
one plugged flow channel, wherein the volume of high heat capacity
material is configured to recover and store cold energy from the LG
from the regasification system for subsequent use at a second
location to provide at least a portion of a cold energy requirement
for liquefaction of a second volume of gas into a second volume of
LG.
32. The system of claim 31, wherein the heat exchange apparatus is
selected from the group consisting of: a plate-fin heat exchanger,
a plate-frame heat exchanger, a printed-circuit heat exchanger,
spiral-wound heat exchanger, and any combination thereof, wherein
the heat exchanger alternates from the at least one plugged flow
channel to the at least one open flow channel.
33. The system of claim 32, wherein the at least one plugged flow
channel further includes a non-condensible gas and the volume of
high heat capacity materials includes a phase-change material (PCM)
configured to utilize at least the latent heat of vaporization.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application Nos. 61/151,765 filed Feb. 11, 2009 and 61/161,683
filed Mar. 19, 2009.
FIELD OF THE INVENTION
[0002] The disclosure relates generally to methods and systems for
efficiently and effectively liquefying, transporting, and
delivering liquefied gas to commercial markets from production
locations. More particularly, the disclosed systems, apparatuses,
and associated methods relate to recovering and storing the cold
thermal energy from the regasification of liquefied gases for later
use in a liquefaction process or apparatus utilizing a regenerative
heat exchange apparatus.
BACKGROUND
[0003] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
[0004] Increasingly, the world's energy needs are being met by
natural gas, which is a cleaner alternative to coal and other
hydrocarbons. However, much of the world's natural gas is located
in reservoirs that are far removed from existing infrastructure
(e.g. pipelines). Such natural gas resources are known as "remote
gas." Some estimates place the amount of the world's natural gas
resources considered to be "remote gas" at nearly 40 percent the
total amount of natural gas in the ground. The remote location of
the gas makes it highly energy inefficient and economically
inefficient to recover and transport due to its very low energy to
volume and energy to mass ratios. Liquefying the natural gas (LNG)
is one common method of improving the transportation economics of
delivering natural gas to consuming markets.
[0005] In remote gas commercialization based on LNG, energy is
expended to liquefy natural gas at the production site and a
comparable amount of thermal energy expended to convert the liquid
back to gas for use at an import terminal. The cold thermal energy
associated with vaporizing the liquid is not utilized. This
constitutes a significant source of energy inefficiency in the
remote gas commercialization chain.
[0006] Attempts to recover and re-use the cold energy associated
with the re-gasification of LNG at the import terminal have evolved
to using the cold energy to liquefy nitrogen, ship the liquid
nitrogen (LN.sub.2) back to the export terminal for use as
refrigerant in the LNG liquefaction process. Two types of
approaches have been proposed in patents such as British Pat. No.
1,170,329 and British Pat. No. 2,333,148. In the first approach,
typified by a disclosure in the '329 patent, up to the maximum
amount of cold energy available is recovered from the LNG during
the re-gasification process at the import terminal and used in a
process to liquefy nitrogen which is shipped back to the export
terminal in the same LNG ship without any modifications. The
resulting liquid nitrogen shipped is typically about half the
volume of the LNG (corresponding to about the same mass as the
LNG). This appears to simplify the transportation segment of the
chain but the reduction in the refrigeration required at the export
terminal is not large and significant supplemental refrigeration is
still needed to produce the LNG. Further, there are technical
challenges associated with shipping partially-filled liquid tanks
due to high sloshing loads in the containers encountered, for
example, during a storm. Finally, there is substantial energy
required to produce the high-purity nitrogen required for the
process, typically in an Air Separation Unit (ASU).
[0007] In the second approach, disclosed in both the '329 and the
'148 patents, enough liquid nitrogen (LN.sub.2) is shipped back to
the export terminal to provide the total refrigeration required to
liquefy the natural gas. Thus no supplemental refrigeration is
needed at the export terminal. The liquid nitrogen required for
this approach is substantial (about the same volume as the LNG
which translates to almost twice the mass of the LNG).
Consequently, large supplemental refrigeration is required at the
import terminal beyond what is available from regasifying the LNG.
Again, there is substantial energy required to produce the
high-purity nitrogen required for the process, typically in an Air
Separation Unit (ASU), in addition to the energy for the
supplemental refrigeration required to liquefy the nitrogen.
Further, structural changes to the LNG ship are needed to transport
the increased mass. These proposed patented approaches have never
been commercially implemented.
[0008] Proposals that have seen limited commercial applications
include utilizing the cold energy for power generation at the
import terminal, or to provide refrigeration for example for
preserving food. However, these options are limited to niche
applications and require specific synergies for them to be
economically viable. Consequently, these proposals have not been
widely implemented.
[0009] What is needed is a method and system to improve the thermal
efficiency of the remote gas commercialization chain utilizing high
heat capacity heat exchange.
SUMMARY
[0010] One embodiment of the present invention discloses a heat
transfer system. The system includes a regasification system at a
first location configured to convert a first volume of liquefied
gas (LG) contained at or below a liquefaction temperature into a
first volume of gas at above the liquefaction temperature, the
regasification system comprising a heat exchange apparatus. The
heat exchange apparatus includes a regenerator matrix having a
volume of high heat capacity materials configured to recover and
store cold energy from the LG from the regasification system for
subsequent use at a second location to provide at least a portion
of a cold energy requirement for liquefaction of a second volume of
gas into a second volume of LG.
[0011] Another embodiment of the present invention discloses a heat
transfer system. The heat transfer system includes a liquefaction
system at a first location configured to convert a first volume of
gas at above a liquefaction temperature into a first volume of
liquefied gas (LG) contained at or below the liquefaction
temperature, the liquefaction system comprising a heat exchange
apparatus. The heat exchange apparatus includes a regenerator
matrix including a volume of high heat capacity materials
configured to provide cold energy to the first volume of gas in the
liquefaction system, wherein the cold energy is obtained from a
regasification system at a second location configured to regasify a
second volume of LG contained at liquefaction temperatures.
[0012] A third embodiment of the present invention discloses a heat
transfer system. The heat transfer system includes a heat exchange
apparatus. The heat exchange apparatus having a regenerator matrix
including a volume of high heat capacity materials, wherein the
regenerator matrix is configured to: a) recover and store cold
energy from a volume of liquefied gas at or below a liquefaction
temperature from a regasification system at a first location; and
b) provide cold energy to a volume of gas at above the liquefaction
temperature in a liquefaction system at a second location.
[0013] In a fourth embodiment of the presently disclosed concepts,
a method of delivering liquefied natural gas (LNG) is provided. The
method includes flowing LNG to a heat exchange apparatus from an
LNG storage tank on an LNG carrier at an LNG gasification location;
recovering cold energy from the LNG using the heat exchange
apparatus having a regenerator matrix including a volume of high
heat capacity materials to form at least partially vaporized
natural gas; storing the cold energy in the high heat capacity
materials for use at an LNG liquefaction location; and delivering
the at least partially vaporized natural gas to a consuming
market.
[0014] In a fifth embodiment of the presently disclosed concepts, a
method of producing natural gas is provided. The method includes
feeding a natural gas stream to a heat exchange apparatus on a
liquefied natural gas (LNG) carrier from a producing location; and
passing the natural gas stream through the heat exchange apparatus
having a regenerator matrix including a volume of high heat
capacity materials. Passing the natural gas through the heat
exchange apparatus includes a) imparting cold energy from the high
heat capacity materials to the natural gas to form at least
partially liquefied natural gas; and b) storing heat energy in the
high heat capacity materials for use at an LNG gasification
location. The method further includes storing the at least
partially liquefied natural gas on the LNG carrier.
[0015] In a sixth embodiment of the present disclosure, an
alternative heat transfer system is provided. The system includes a
regasification system at a first location configured to convert a
first volume of liquefied gas (LG) contained at or below a
liquefaction temperature into a first volume of gas at above the
liquefaction temperature, the regasification system comprising a
heat exchange apparatus. The heat exchange apparatus includes a
shell and tube heat exchanger. The shell and tube heat exchanger
includes a) a sealed tube bundle containing a volume of high heat
capacity material; and b) the shell side is configured to receive
the first volume of liquefied gas (LG) to provide the cold energy
stored in the tube bundle, wherein the volume of high heat capacity
material is configured to recover and store cold energy from the LG
from the regasification system for subsequent use at a second
location to provide at least a portion of a cold energy requirement
for liquefaction of a second volume of gas into a second volume of
LG.
[0016] In a seventh embodiment of the present disclosure, an
alternative heat transfer system is provided. The system includes a
liquefaction system at a first location configured to convert a
first volume of gas at above a liquefaction temperature into a
first volume of liquefied gas (LG) contained at or below the
liquefaction temperature, the liquefaction system comprising a heat
exchange apparatus. The heat exchange apparatus includes a shell
and tube heat exchanger, comprising a) a sealed tube bundle
containing a volume of high heat capacity material; and b) the
shell side is configured to receive the first volume of liquefied
gas (LG) to receive the cold energy to the volume of high heat
capacity material in the sealed tube bundle, wherein the volume of
high heat capacity material is configured to provide cold energy to
the first volume of gas in the liquefaction system, wherein the
cold energy is obtained from a regasification system at a second
location configured to regasify a second volume of LG contained at
liquefaction temperatures. In each of the sixth and seventh
embodiments, the systems may include a phase-change material (PCM)
configured to utilize at least the latent heat of vaporization and
a non-condensible gas in the sealed tubes.
[0017] In an eighth embodiment of the present disclosure, a method
of delivering liquefied natural gas (LNG) is disclosed. The method
includes flowing LNG to a heat exchange apparatus from an LNG
storage tank on an LNG carrier at an LNG gasification location;
passing the LNG through the heat exchange apparatus having a shell
and tube heat exchanger including sealed tubes containing a volume
of high heat capacity material; recovering cold energy from the LNG
utilizing the shell and tube heat exchanger to form at least
partially vaporized natural gas; storing the cold energy in the
high heat capacity materials for use at an LNG liquefaction
location; and delivering the at least partially vaporized natural
gas to a consuming market. The shell and tube heat exchanger may
include a phase-change material (PCM) configured to utilize at
least the latent heat of vaporization and a non-condensible gas in
the sealed tubes.
[0018] In a ninth embodiment, a heat transfer system is provided.
The system includes a regasification system at a first location
configured to convert a first volume of liquefied gas (LG)
contained at or below a liquefaction temperature into a first
volume of gas at above the liquefaction temperature, the
regasification system comprising a heat exchange apparatus. The
heat exchange apparatus including a cross-flow heat exchanger,
comprising: a) at least one plugged flow channel containing a
volume of high heat capacity material; and b) at least one open
flow channel configured to receive the first volume of liquefied
gas (LG) to provide cold energy to the volume of high heat capacity
material in the at least one plugged flow channel, wherein the
volume of high heat capacity material is configured to recover and
store cold energy from the LG from the regasification system for
subsequent use at a second location to provide at least a portion
of a cold energy requirement for liquefaction of a second volume of
gas into a second volume of LG.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] The foregoing and other advantages of the present techniques
may become apparent upon reviewing the following detailed
description and drawings in which:
[0020] FIG. 1 shows an exemplary diagram of one embodiment of a
heat transfer system including a heat exchange apparatus in
accordance with certain aspects of the present disclosure;
[0021] FIG. 2 shows an exemplary diagram of an alternative
embodiment of the heat transfer system of FIG. 1;
[0022] FIG. 3 shows an exemplary diagram of an alternative
embodiment of the heat transfer system of FIGS. 1 and 2;
[0023] FIGS. 4A-4C are illustrations of flow charts of methods of
operating one of a regasification unit, a liquefaction unit, and an
integrated unit in accordance with certain embodiments of FIGS.
1-3;
[0024] FIGS. 5A-5B show an exemplary embodiment of the heat
exchange apparatus of FIGS. 1-3 in two modes of operation;
[0025] FIGS. 6A-6E show various particular embodiments of heat
exchange apparatuses utilizing phase-change materials in the heat
exchange arrangements of FIGS. 1-3;
[0026] FIGS. 7A-7C are graphs showing the effect on the thermal
energy consumption using a single composite material; and
[0027] FIG. 8 is an illustration of the arrangement of an exemplary
group of materials with respect to the fluid flow paths and
temperatures of flow streams of FIGS. 1-3.
DETAILED DESCRIPTION
[0028] In the following detailed description section, the specific
embodiments of the present techniques are described in connection
with preferred embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the present techniques, this is intended to be
for exemplary purposes only and simply provides a description of
the exemplary embodiments. Accordingly, the invention is not
limited to the specific embodiments described below, but rather, it
includes all alternatives, modifications, and equivalents falling
within the true spirit and scope of the appended claims.
[0029] The term "liquefaction temperature," as used herein, means a
temperature at which a gas is converted to a liquid. The
liquefaction temperature of a gas will change with pressure, so a
single gas may have more than one liquefaction temperature,
depending on the pressure of the gas. Further, this term applies to
mixtures of gases, such as, for example, air and natural gas. The
composition of natural gas may vary by location or by the inclusion
or exclusion of certain pre-treating process steps and the
liquefaction temperature will vary somewhat with variations in the
composition of such gases. The term is intended to include any and
all such variations in pressure and temperature.
[0030] In one exemplary embodiment of the present invention, a heat
transfer system is provided, which may include a regasification
system for converting liquefied gas at a liquefaction temperature,
such as, for example, liquefied natural gas (LNG), from a liquid to
a vapor phase (e.g. natural gas) at above a liquefaction
temperature for the gas. The system may further include a heat
exchange apparatus having a regenerator matrix containing a volume
of high heat capacity materials (a.k.a. thermal energy storage
materials), which may be phase-change materials in some exemplary
embodiments. The heat exchange apparatus may further be configured
to recover and store the cold energy (e.g. refrigeration effect)
from the cryogenically stored liquefied gas as the liquefied gas is
vaporized. The regenerator matrix is configured to store the cold
energy in the high heat capacity materials long enough to transport
it to a second location to perform a liquefaction operation
utilizing the cold energy for at least a portion of the cooling
needed to liquefy gas from a vapor phase.
[0031] In an alternative exemplary embodiment of the present
invention, a heat transfer system including a liquefaction system
for converting a first volume of feed gas at above liquefaction
temperature from a substantially gaseous phase to a substantially
liquid phase (e.g. a first volume of liquefied gas) is provided.
The liquefaction system further includes a heat exchange apparatus
having a regenerator matrix including a volume of high heat
capacity materials configured to provide cold energy to the first
volume of gas in the liquefaction system, wherein the cold energy
is obtained from a regasification system at a second location
configured to re-gasify a second volume of liquefied gas contained
at liquefaction temperatures.
[0032] In one exemplary embodiment, the re-gasification system and
the liquefaction system may be integrated and utilize the same heat
exchange apparatus. The high heat capacity materials may include
phase change materials (PCMs) and may be configured in the
regenerator matrix as micro-encapsulated spheroids,
macro-encapsulated spheroids, micro-encapsulated sheets,
macro-encapsulated sheets, macro-encapsulated honey-comb network,
or a micro-encapsulated honey-comb network. The PCMs may be a
series of phase-change materials (PCMs) stacked sequentially based
on a phase transition temperature of the PCMs or may be a
thermo-adjustable mixture, which allows the phase transition
temperature to be tuned based on the composition of the mixture.
The mixture may comprise at least two unique PCMs, wherein each PCM
has a different phase transition temperature range. In this
exemplary embodiment, an integrated production, transport, and
re-gasification system (PTRS) is provided. One specific embodiment
provides for the integration of the LNG production system, the LNG
transport system, and the LNG regasification system into a single
unit (LNG-PTRS) through the use of a heat exchange system. Such an
integrated system may further utilize the liquefaction system to
reliquefy boil-off gas during transit.
[0033] Additional embodiments include methods of re-gasifying and
delivering natural gas to an import terminal as well as liquefying
and producing natural gas at a production location utilizing
embodiments of the systems disclosed herein.
[0034] Still further alternative embodiments may incorporate a
shell and tube heat exchanger instead of the regenerator matrix,
wherein the tubes may be filled with a high heat capacity material
and a non-condensible gas. In particular, the high heat capacity
material may be a phase change material (PCM) that takes advantage
of the latent heat of vaporization for a liquefaction temperature
of interest. A cross-flow heat exchanger with alternating flow
channels having high heat capacity materials may also be used.
[0035] The disclosed embodiments also provide substantial
advantages over building an LNG production facility on an offshore
platform. For example, the disclosed systems and methods eliminate
the need for several large LNG storage tanks on a platform;
eliminate the technical challenges associated with cryogenic liquid
transfer between an offshore platform and an LNG ship (only a gas
connection is needed between the resource and the LNG ship); and
eliminate the enormous space and weight requirements for an LNG
production facility on an offshore platform.
[0036] The presently disclosed systems and methods also have
several advantages over the prior art. The presently disclosed
systems and methods do not require costly and energy intensive air
separation units (ASU), as required by systems utilizing liquefied
nitrogen to transfer cold energy, and since air is not used, there
is no risk of forming a combustible mixture as there is with
systems utilizing liquefied air. The presently disclosed systems
and methods also eliminate the risks associated with shipping
storage tanks partially filled with liquid, which places a carrier
at risk due to sloshing loads on the storage tanks from the
liquid.
[0037] Referring now to the figures, FIG. 1 shows an exemplary
diagram of one embodiment of a heat transfer system including a
heat exchange apparatus in accordance with certain aspects of the
present disclosure. The heat transfer system disclosed in FIG. 1
includes a regasification system 100 having a container or tank 102
for holding liquefied gas at or below its liquefaction temperature,
a line 104 for delivering the liquefied gas to a pump 106
configured to pressurize the liquefied gas, a line 108 for
delivering the pressurized, liquefied gas to a heat exchange
apparatus 110 configured to vaporize the pressurized liquefied gas,
and a line 112 for delivering the vaporized gas.
[0038] In some exemplary embodiments of the regasification system
100, the liquefied gas is liquefied natural gas (LNG), but may
alternatively be liquefied propane gas (LPG), liquefied carbon
dioxide gas, liquefied nitrogen gas, liquefied air, liquefied
oxygen, liquefied neon, liquefied hydrogen, or some combination
thereof. The container 102 may be any type of container suitable
for transporting liquefied gases, such as a spherical tank
container, a membrane tank container, a corrugated tank container,
a prismatic tank container, or other type of container. The line
104 may be any type of conduit or flow line suitable for delivering
liquefied gases. The line 104 should be large enough to flow the
liquefied gas at a rate sufficient to support efficient
regasification operations. It is contemplated that the line 104 may
include insulation, have a corrosion resistant coating, a
low-friction loss coating, another performance-enhancing coating,
and any combination thereof. The container 102 and the line 104
should be capable of operation at temperatures from at least about
-253 degrees Celsius (.degree. C.) to about 40.degree. C. and have
joints and other design features to permit the container 102 and
the line 104 to cyclically contract and expand between these
temperatures without failure for the life of the system 100. It is
contemplated that a person of ordinary skill in the art has been
provided with sufficient information to engineer the container 102
and line 104 in accordance with the present disclosure.
[0039] In some embodiments of the regasification system 100, the
pump 106 may be a series of multiple pumps or one large pump. The
pump 106 should be configured to handle liquefied gases at
temperatures ranging from about -253.degree. C. to about
-60.degree. C. or from about -196.degree. C. to about -100.degree.
C. and should be capable of handling stress due to expansion and
contraction cycles over a temperature range of about -253.degree.
C. to about 40.degree. C. The pump 106 should further be capable of
providing a sufficient flow rate of the liquefied gas through the
system 100 for normal unloading and regasification operations. In
some particular, exemplary embodiments, a reciprocating pump, a
centrifugal pump, a cryogenic pump, or any combination of these
types of pumps may be utilized in accordance with the present
disclosure.
[0040] The line 108 may have many of the same features as line 104,
however the liquefied gas flowing through line 108 is expected to
have a somewhat higher temperature and pressure than the liquefied
gas in line 104 because it passes through the pump 106.
[0041] The heat exchange apparatus (heat exchanger) 110 may include
a regenerator matrix, a shell and tube arrangement, a plate-fin
arrangement, or other configuration having high heat capacity
materials configured to recover and store cold energy from the
liquefied gas (LG) for subsequent use at a second location (e.g. a
liquefaction location) to provide at least a portion of a cold
energy requirement for liquefaction of a second volume of gas (e.g.
a feed gas) into a second volume of LG. In some exemplary
embodiments, the high heat capacity materials may be a series of
phase-change materials (PCMs) stacked sequentially based on a phase
transition temperature of the PCMs, may include a thermo-adjustable
mixture of materials which allow the phase transition temperature
to be tuned based on the composition of the mixture. The mixture
may comprise at least two PCMs each having a different phase
transition temperature, or may be a combination of these
configurations.
[0042] The heat exchanger 110 may be a fixed bed regenerator, a
compact regenerator, a micro-scale regenerator, or some combination
of these. In particular embodiments, the heat exchanger 110 may
include a regenerator matrix including one of micro-encapsulated
spheres, macro-encapsulated spheroids, micro-encapsulated sheets, a
micro-encapsulated honey-comb network, macro-encapsulated sheets,
macro-encapsulated honeycomb network, or some combination of
these.
[0043] Alternatively, the heat exchanger 110 may comprise a shell
and tube arrangement having high heat capacity materials in the
tubes configured to recover and store cold energy from the
liquefied gas (LG) for subsequent use at a second location (e.g. a
liquefaction location) to provide at least a portion of a cold
energy requirement for liquefaction of a second volume of gas (e.g.
a feed gas) into a second volume of LG. In the shell and tube
example, the high heat capacity materials may be PCMs and include a
thermo-adjustable mixture of materials which allow the phase
transition temperature to be tuned based on the composition of the
mixture. Additionally, the high heat capacity materials in this
arrangement may include materials utilizing at least the latent
heat associated with vapor-liquid phase transition--(latent heat of
vaporization or condensation). Note, these materials may also
utilize the liquid-solid phase transition similar to the PCM's
discussed above.
[0044] The regasification system 100 further includes a line 112
from the heat exchanger 110 to one of a vaporized gas delivery or
offloading system, or may optionally include a supplemental heat
exchange system 114 with optional supporting equipment 114a such as
pumps, condensers, and boilers to further vaporize the gas after it
passes through the heat exchanger 110. The line 112 may be
configured to carry vaporized gas after it passes through the heat
exchanger 110. As such, it is expected that the gas will be at a
temperature of from about -10.degree. C. to about 80.degree. C., or
from about 0.degree. C. to about 60.degree. C., depending on the
operation of the heat exchanger 110, the ambient temperature,
implementation of an optional heat exchange system 114, the initial
temperature of the liquefied gas (LG), and other factors. As such,
line 112 may have a larger diameter than lines 108 and 104, may not
include insulation and may have a composition with less nickel as
lines 104 and 108 because line 112 may not operate at or below
cryogenic liquefaction temperatures.
[0045] The optional heat exchange system 114 may be an electrical
heater, may burn some of the vaporized gas for heat, may use
ambient air or water, may utilize concentrated solar energy, or
impart heat to the at least partially vaporized gaseous stream in
line 112 by some other means. In some embodiments, power for the
optional heat exchange system 114 may be generated by a co-located
power plant, such as on a ship, on-shore, or off-shore structure
having the regasification system 100. A person of ordinary skill in
the art will understand the engineering variables to consider in
determining the placement, capacity, efficiency, and type of heat
exchanger, if such an apparatus is utilized.
[0046] FIG. 2 shows an exemplary diagram of an alternative
embodiment of the heat transfer system of FIG. 1. As such, FIG. 2
may be best understood with reference to FIG. 1. The heat transfer
system includes a liquefaction system 200 having a line 202 for
delivering a feed gas, a heat exchange apparatus 110, a line 204
for carrying the condensed, cooled feed gas from the regenerator to
a container 102 for storing liquefied gas. Optionally, the system
200 may also include a supplemental heat exchanger 206 for
sub-cooling the gas, a line 208 to carry the further cooled gas to
an optional expander 210, and a line 212 to carry the liquefied gas
to the liquefied gas container 102. Another optional embodiment of
the system 200 may include a supplemental heat exchange system 214
for pre-cooling the gaseous feed stream before entering the heat
exchanger 110.
[0047] The line 202 for carrying the gaseous feed may be similar to
the line 112, as it may be configured to carry a substantially
gaseous feed, such as natural gas from a production location at
substantially atmospheric or slightly higher temperatures and above
ambient pressure. The line 202 may not require insulation and may
have a larger diameter than some of the other lines, but may be
sized to handle sufficient amounts of gas to supply the system 200.
The gas may be a natural gas (NG), but may alternatively be propane
gas (PG), carbon dioxide gas, nitrogen gas, air, oxygen, neon,
hydrogen, or some combination thereof.
[0048] The heat exchange apparatus 110 may be the same or similar
to the heat exchange apparatus (heat exchanger) 110 of the
regasification system 100. In one embodiment, the heat exchanger
110 includes high heat capacity materials configured to provide
cold energy to the feed gas in the liquefaction system 200. The
cold energy is obtained from a regasification system (e.g.,
regasification system 100) at a second location (e.g. a delivery or
offloading location) configured to regasify another volume of
liquefied gas contained at liquefaction temperatures. In some
exemplary embodiments, the high heat capacity materials may be a
series of phase-change materials (PCMs) stacked sequentially based
on a phase transition temperature of the PCMs, may include a
thermo-adjustable mixture of materials which allow the phase
transition temperature to be tuned based on the composition of the
mixture. The mixture may comprise at least two PCMs each having a
different phase transition temperature, or may be a combination of
these configurations.
[0049] The heat exchanger 110 may be a fixed bed regenerator, a
compact regenerator, a micro-scale regenerator, a shell and tube
heat exchanger, or some combination of these. In particular
embodiments, the heat exchanger may include a regenerator matrix,
which may be comprised of micro-encapsulated spheres,
macro-encapsulated spheroids, micro-encapsulated sheets, a
micro-encapsulated honey-comb network, macro-encapsulated sheets,
macro-encapsulated honey-comb network, or some combination of
these. Alternatively, the high heat capacity materials may be
enclosed in sealed tubes in a shell and tube heat exchanger
arrangement, or a cross-flow heat exchanger arrangement having
alternating flow channels with high heat capacity materials
therein.
[0050] The line 204 is configured to carry gas that may be at least
partially liquefied and at or below liquefaction temperatures and
at high pressures. Line 204 may be the same or similar to line 108.
Lines 208 and 212 are optional and may be the same or similar to
line 204, line 108, and line 104, which are configured to safely
and efficiently transport a substantially liquefied gas at
liquefaction temperatures and above ambient pressures.
[0051] The system 200 may further include optional supplemental
cooling systems 206 and/or 214. Supplemental cooler 206 may include
additional equipment 206a such as pumps, chillers, and/or expanders
and may be utilized for sub-cooling the gaseous stream if the heat
exchanger 110 fails to sufficiently liquefy the gas for transport
and supplemental cooler 214 may include additional equipment 214a
such as pumps, chillers, and/or expanders and may be utilized for
pre-cooling the gaseous stream before entering the heat exchanger
110 to ensure sufficient liquefaction of the gas for transport. The
cooling may be accomplished by utilizing any reasonably applicable
heat exchanger such as a co-current or counter-current heat
exchanger, a finned heat exchanger, direct contact heat exchanger,
another type of heat exchanger, or some combination of these. The
refrigerant may be obtained from cold sea water, a mixed
refrigerant system, an HPXP system, or some combination of these.
Power for the system may be generated by a co-located power plant,
such as on a ship, on-shore, or off-shore structure, by a solar
array, by burning a fuel gas, or some combination of these. A
person of ordinary skill in the art will understand the engineering
variables to consider in determining the placement, capacity,
efficiency, and type of optional supplemental cooler to install and
utilize.
[0052] The optional expander 210 may be configured to provide
supplemental cooling and liquefaction of the cooled stream prior to
storage in the container 102. The container 102 is the same or
similar to the container 102 in the regasification system 100. The
expander 210 may be capable of cryogenic operation. The expander
may be a dual expander, a hydraulic turbine, a turbo expander, a
throttling valve, or some combination of these. Depending on the
ambient conditions, composition of the feed gas, and other factors,
the expander 210 may not be needed and may be bypassed.
[0053] FIG. 3 shows an exemplary diagram of an alternative
embodiment of the heat transfer system of FIGS. 1 and 2. As such,
FIG. 3 may be best understood with reference to FIGS. 1 and 2. The
heat transfer system 300 includes a regasification system 100 and a
liquefaction system 200 integrated into a single system. The
integrated system 300 is installed on a platform 302 and includes
connections for receiving a feed gas via line 308, which may be
delivered by line 304 to a gas pre-treatment unit 306. The system
300 further includes a pipeline 312 for delivery of vaporized gas
to a consuming market. In addition to or instead of pre-cooler 214,
the system 300 may include a pre-cooler 310 with a compressor 310a
and a chiller 310b.
[0054] The platform 302 may be a carrier, such as an LNG carrier,
or a barge or other facility. In some embodiments, the platform 302
will be capable of moving from a regasification location to a
liquefaction location which may be separated by a distance of from
100 miles to about 15,000 miles or from about 1,000 miles to about
10,000 miles, or from about 3,000 miles to about 6,000 miles. The
optional equipment 310, 214, and 114 may be on the platform 302 or
located at a loading or unloading location.
[0055] The pretreatment unit 306 may be located at a gas production
location or connected by pipeline to such a location. The
pretreatment unit 306 may be configured depending on the quantity
and quality of the gas for treating, but may include a liquids
separation portion or water-knockout portion to remove any
hydrocarbon or aqueous liquids from the feed gas stream. The unit
306 may further include an acid gas removal or separation unit to
remove carbon dioxide, hydrogen sulfide, and other unwanted gases,
depending on the composition of the feed gas. Such a separation
unit may include an amine unit, a membrane separation unit, an
adsorption unit, or similar unit, or some combination thereof. A
person of ordinary skill in the art will understand the engineering
variables to consider in selecting the type of unit, placement,
capacity, efficiency, and power requirements and utilize for the
pretreatment unit 306.
[0056] The pipeline 312 may be operably connected to gas handling
system, a gas storage facility, a gas distribution network, or any
combination thereof (not shown). In some embodiments, the vaporized
gas product is delivered to a gas consuming market via the
available gas receiving and handling system at that particular
location. The facilities may vary significantly from one location
to another. Exemplary gas consuming markets include the United
States, Japan, China, Italy, Great Britain, and others. Delivery
locations may be located offshore or onshore. The system 300 may be
configured to be interoperable with any or all of these gas
delivery locations.
[0057] The heat exchange apparatus 110 is configured to recover and
store cold energy from a volume of liquefied gas at liquefaction
temperatures from a regasification system 100 at a first location;
and provide cold energy to a volume of gas at above liquefaction
temperatures in a liquefaction system 200 at a second location.
[0058] The integrated system 300 may be utilized with an integrated
production, transport, and re-gasification system (PTRS). The
production system may be liquefaction system 200, the transport may
be carrier or barge 302, and the re-gasification system may be
re-gasification system 100. In particular, such an integrated unit
may be utilized to deliver liquefied natural gas (LNG) to
commercial markets from remote production location. Such an
integrated LNG unit may be referred to as an LNG-PTRS. In one
exemplary advantageous embodiment, the PTRS may further utilize the
liquefaction system to reliquefy boil-off gas during transit. For
example, as the carrier 302 transports the liquefied gas from the
producing location to the delivery location some of the liquefied
gas in the container 102 may boil off or vaporize. The stored cold
energy in the heat exchange apparatus 110 may be utilized to
reliquefy this boil-off gas and return it to the container 102 in
liquid form.
[0059] In another exemplary embodiment, any of the systems 100,
200, or 300 may utilize an instrumentation and control system (not
shown) for safely and efficiently operating the systems 100, 200,
or 300. For example, various sensors at a plurality of locations
may be utilized to measure temperature and pressure of the gas in
liquid or vapor form. Input from such sensors may be utilized to
determine the amount of supplemental heat that may be added via the
supplemental heat exchanger 114, the amount of supplemental cooling
that may be added via the supplemental cooler 214 or 206, and the
expander 210. Such a control system may also control the flow rate
of the liquefied gas via the pump 106 or the reliquefaction of
boil-off gas. The control system may be programmed to operate
automatically via a programmable computer system having software
instructions, may include manual inputs, a graphical user interface
(GUI), and may include manual overrides, such as valves or switches
in a central location or throughout the system 100, 200, or 300 at
particular locations. It is contemplated that a person of ordinary
skill in the art has been provided with sufficient information to
engineer the control system in accordance with the present
disclosure.
[0060] FIGS. 4A-4C are illustrations of flow charts of methods of
operating one of a regasification unit, a liquefaction unit, and an
integrated unit in accordance with certain embodiments of FIGS.
1-3. As such, FIGS. 4A-4C may be best understood with reference to
FIGS. 1-3. The method 400 includes delivering 402 liquefied natural
gas (LNG) to a heat exchange apparatus from an LNG storage tank on
an LNG carrier at an LNG gasification location, recovering 404 cold
energy from the LNG utilizing the heat exchange apparatus having a
regenerator matrix including a volume of high heat capacity
materials to form at least partially vaporized natural gas and
storing 406 the cold energy in the high heat capacity materials for
use at an LNG liquefaction location, then delivering 408 the at
least partially vaporized natural gas.
[0061] In some embodiments of the disclosure, the LNG storage tank
may be container 102 and the LNG carrier may be an LNG-PTRS, which
may be represented by platform 302. In some embodiments of the
invention, the heat exchange apparatus is the heat exchange
apparatus 110. The heat exchanger 110 may be included in the
regasification system 100 or the integrated system 300. In
addition, the liquefaction location may include a liquefaction
system 200. The delivering step 410 may include the utilization of
pipeline 312.
[0062] Referring to FIG. 4B, the method 450 includes feeding 452 a
natural gas stream to a heat exchange apparatus on a liquefied
natural gas (LNG) carrier from a producing location and passing 454
the natural gas stream through the heat exchange apparatus having a
regenerator matrix including a volume of high heat capacity
materials. The heat exchange apparatus is configured to impart 456
cold energy from the high heat capacity materials to the natural
gas to form at least partially liquefied natural gas and store 458
heat energy in the high heat capacity materials for use at an LNG
gasification location. The method 450 further includes storing 460
the at least partially liquefied natural gas on the LNG
carrier.
[0063] In some embodiments of the disclosure, natural gas may be
fed via line 202 in the liquefaction system 200 or via line 304 in
the integrated system 300. In some embodiments of the invention,
the heat exchange apparatus is the heat exchange apparatus 110. The
heat exchanger 110 may be included in the liquefaction system 200
or the integrated system 300. In addition, the gasification
location may include a regasification system 100. The storing step
460 may include the utilization of container 102.
[0064] Referring now to FIG. 4C, the method 470 includes delivering
472 liquefied natural gas (LNG) to a heat exchange apparatus from
an LNG storage tank on an LNG carrier at an LNG gasification
location, recovering 474 cold energy from the LNG using the heat
exchange apparatus having a shell and tube heat exchanger including
sealed tube bundles containing a volume of high heat capacity
material to form at least partially vaporized natural gas, storing
476 the cold energy in the high heat capacity materials for use at
an LNG liquefaction location, then delivering 478 the at least
partially vaporized natural gas. In some embodiments, the tube
sheets may include a non-condensible gas to account for the volume
change if the high heat capacity materials are phase change
materials over the heat of vaporization and may include a connected
buffer volume to hold such a gas during high volume phase
shifts.
[0065] FIGS. 5A and 5B show an exemplary embodiment of the heat
exchange apparatus of FIGS. 1-3 in two modes of operation. As such,
FIGS. 5A and 5B may be best understood with reference to FIGS. 1-3.
FIG. 5A is an exemplary embodiment of a portion of a liquefaction
flow system 500 including the heat exchange apparatus 110 as it may
operate in the liquefaction system 200. The liquefaction flow
system 500 includes a vessel 502 configured to enclose the heat
exchange apparatus 110, flow valves 504a, 504b, 504c, and 504d
configured to control fluid flow via lines 202, 112, 108, and 204,
respectively.
[0066] Valves 504a and 504d are shown in the open position to
permit fluid flow through lines 202 and 204, while valves 504b and
504c are shown in the closed position to prevent fluid flow in the
opposing direction via lines 108 and 112. In one alternative
embodiment, valve 504a may be open while valve 504d is closed. For
example, when the initial feed gas stream is fed to the heat
exchanger 110 via line 202, valve 504d may remain in the closed
position until the feed gas (which is now much colder and may be at
least partially liquefied) reaches valve 504d and some pressure is
built up. In other words, the valves 504a and 504d may be operated
based on the pressure requirements of the liquefaction system 200,
which may depend on the feed gas composition, initial temperature,
flow rate, flow volume, and other factors. Alternatively, as the
process comes to an end, valve 504a may be closed while 504d
remains open.
[0067] FIG. 5B shows an exemplary embodiment of a portion of a
re-gasification flow system 520 including the heat exchange
apparatus 110 as it may operate in the re-gasification system 100.
As shown, the re-gasification flow system 520 is similar to the
liquefaction flow system 500, but with valves 504b and 504c open to
permit flow of fluid streams through the heat exchange apparatus
110 and valves 504a and 504d closed to prevent fluid flow in the
opposing direction. As noted with respect to system 500, the valves
may be operated to open and close at different times, depending
upon the operational needs.
[0068] In some exemplary embodiments of the disclosed systems 500
and 520, the valves 504a-504d may all be of the same or similar
design, but alternatively, the valves 504a-504d may be
independently selected based on expected operating conditions. For
example, it is expected that valve 504a may be configured to handle
primarily gaseous feed streams at relatively high temperatures
(e.g. from about 0.degree. C. to about 120.degree. C.) and
relatively high pressures (e.g. from about 1 atmosphere (atm) to
about 20 atm), depending on the feed gas source. However, valve
504d may be expected to handle gas and liquid (multiphase) streams
at significantly lower temperatures (e.g. from about -200.degree.
C. to about -20.degree. C.). As such, valve 504d may have different
sizing, material selection, and operating parameters than valve
504a. Similarly, valve 504b is expected to handle fluid streams
similar to the streams handled by valve 504a, but may require
operation at a slightly lower temperature and pressure and valve
504c may be required to handle fluid streams similar to that of
valve 504d. In one exemplary embodiment, valves 504a and 504b may
be the same valve, capable of operation in both directions
(liquefaction 500 and re-gasification 520) and valves 504c and 504d
may be the same valve.
Description of High Heat Capacity Materials
[0069] The high heat capacity materials (also called thermal energy
storage (TES) materials) may be any one or a combination of
phase-change materials (PCMs), molecular alloys, a single composite
material configured to span a temperature range of interest. In one
embodiment, the material of choice includes a high enthalpy change
in the appropriate temperature range (e.g. about 20K (-253.degree.
C.) to about 273K (0.degree. C.) or about 77K (-196.degree. C.) to
about 213K (-60.degree. C.)); phase change temperature in the
appropriate regime of interest; and high mass density. In addition,
the material selected should have low density variation
accompanying the thermal energy changes, high chemical stability
associated with the thermal cycling, and compatibility between the
active phase change material (PCM) and any containment
material.
[0070] Referring now to FIGS. 6A-6E, show various particular
embodiments of heat exchange apparatuses utilizing high heat
capacity materials in the heat exchange arrangements of FIGS. 1-3.
As such, FIGS. 6A-6D may be best understood with reference to FIGS.
1-3. In FIG. 6A, the arrangement 600 includes a regenerator matrix
601 including a first phase change material (PCM) 602, a first
dividing wall 604a, a second PCM 606, a second dividing wall 604b,
a third PCM 608, a third dividing wall 604c, and a fourth PCM 610.
In this exemplary embodiment, the series of materials 602, 606,
608, and 610 are used to transfer thermal energy at discrete
temperatures within the total temperature range of interest. Each
dividing wall 604a-604c may be of the same or similar type, but may
comprise a rigid, porous material that permits the passage of
fluids, but prevents the passage of PCMs from one portion of the
regenerator matrix 601 to another portion thereof. In one
particular embodiment, a plastic annular disc or punched plastic or
other insulating material may be used as a spacer between the
PCMs.
[0071] For example, in a PCM-based solution, the specific heat
capacity of each material 602, 606, 608, and 610 in the series of
materials may also be used to augment the thermal energy storage
capability of the PCM near its phase transition temperature. Thus,
the thermal energy storage capacity of the target material may be
optimized for both the heat of fusion and the integrated value of
the specific heat capacity over the appropriate temperature
interval. There may be flexibility in the material, geometry and
type of encapsulation technology used. The TES system may further
be packaged into a heat exchanger, such as the regenerator matrix
601 in the heat exchange apparatus 110. As such, the form of
encapsulation may guide the development of the heat exchanger
configuration. Additionally, the encapsulation technology may
recognize the need for long term stable behavior of the TES system
(e.g., compatibility between the different materials, minimizing
the potential for adverse impacts of thermal cycling, abrasion,
corrosion etc.). In some embodiments, the material may have a
significantly high density (>1000 kg/m.sup.3).
[0072] FIGS. 6B-6D show an alternative arrangement of the heat
exchange apparatus 110 including a shell and tube heat exchanger.
FIG. 6B shows an exemplary shell and tube heat exchanger
arrangement 620 having a shell 622, a tube bundle with straight
tubes 624, baffles 626 (optional), tube sheets 628a and 628b, a gas
inlet 630, and a gas outlet 632. Such an arrangement 620 may be
particularly suited to PCM's utilizing the heat of vaporization,
involves use of modified tube sheets traditionally used in shell
and tube heat exchangers. FIG. 6C shows a detail view of one
embodiment of the tubes in the tube bundle 624, which are filled
with the PCM material 644 and sealed to provide sufficient thermal
storage capacity. The tube wall material is made of relatively high
thermal conductivity metallic material allowing for good heat
transfer for the thick-wall required. To minimize the induced
stresses due to the large volume change associated with the
vapor-to-liquid phase transition, a non-condensible gas 642, such
as nitrogen or argon, is added to the PCM 644 in the tube 624. An
alternative embodiment of the shell and tube design to accommodate
the volume changes associated with the phase transition is shown in
FIG. 6D, where the non-condensible gas (e.g. nitrogen) is provided
as a buffer 665 in the header for the tube sheet 628b.
[0073] FIG. 6E shows an exemplary cross-flow heat exchanger
apparatus. The cross-flow heat exchanger 680 with open flow
channels 682 for flowing gas or cryogenic liquids 686 therethrough
alternating with plugged flow channels 684 containing high heat
capacity materials and, optionally non-condensible gas therein.
Other traditional heat exchangers such as spiral-wound, brazed
aluminum, printed-circuit or micro-channel heat exchangers may be
used with or without the buffer tank embodiment disclosed
above.
[0074] In one alternative embodiment, the high heat capacity
material (or TES) may comprise a material analogous to phase change
materials (PCMs) made up of molecular alloys (sometimes called
MAPCM) which have the advantage of being thermo-adjustable,
allowing the flexibility to tune the phase transition temperature
through their composition. For example, one configuration may
include a pair of materials, each with high heat of fusion that may
be mixed in different proportions to provide mixtures with phase
transition temperatures in the range of about 77 K to about 273 K,
or from about 100 K to about 250 K or from about 150 K to about 200
K. Such a mixture may be encapsulated to preserve the mixture
composition and thereby ensure a fixed phase transition
temperature. However, individual materials/compounds with high heat
of fusion and/or high specific heat capacity and with phase
transition temperature in the desired ranges may be provided.
[0075] Another variation of the disclosed embodiments includes the
use of a single composite material (SCM) to span the temperature
range of interest. In such an arrangement, the thermal energy
storage capacity for the composite material is the sum of the solid
phase specific heat capacity, the latent heat (of fusion) and the
liquid phase specific heat capacity. Graphs 700, 750, and 760
showing the effect on the thermal energy consumption using such a
material are provided at FIGS. 7A-7C. Such an approach takes
advantage of the combination of the large temperature range for the
application and the specific heat capacity of the composite
material. The composite material is thus chosen to optimize the
integrated heat capacity associated with both the liquid and solid
phases, and the heat of fusion for maximum thermal energy storage.
In an example solution, the total mass required to absorb the
energy associated with a unit mass of LNG is between 0.55 to
0.65.
[0076] Yet another variation of the disclosed embodiments includes
the use of a single composite material (SCM) to span the
temperature range of interest but in an arrangement with an even
higher thermal energy storage capacity. The higher thermal energy
storage capacity comes from utilizing the large latent heat
associated with vapor-liquid phase transition--latent heat of
vaporization (condensation). A graph 760 showing the effect on the
thermal energy consumption using such a material is provided as
FIG. 7C. The composite material is thus chosen to optimize the
integrated heat capacity associated with the liquid and solid
phases, as well as the heat of fusion and the heat of vaporization
for maximum thermal energy storage. In an example solution, the
total mass required to absorb the energy associated with a unit
mass of LNG is between 0.20 to 0.27.
[0077] In addition to the selection and arrangement of the
materials for the regenerator matrix 601, there should also be some
consideration to the encapsulation of such materials to control the
mixing of materials with each other and with the fluid streams 202
and 108. In one exemplary embodiment, the PCM material may be
hermetically sealed to isolate it from the process stream 202 or
108. This may be accomplished by encapsulating the PCM in a form
and geometry such that, when integrated into a heat exchanger,
improves heat transfer effectiveness as well as cost effectiveness.
One exemplary encapsulation approach involves micro-encapsulation
of the PCM to produce geometries, such as spheroids, that may be
incorporated into the regenerator matrix 601 Beneficially, the
regenerator matrix has a high surface area for a given volume,
which provides a small exchanger volume for a given energy density,
effectiveness and pressure drop.
[0078] In another exemplary embodiment, the PCM may be
macro-encapsulated. This may include creating spheroids or sheets
of encapsulated material that may be formed into a heat exchanger.
Heat transfer enhancement techniques, such as fins, may be
incorporated into the chosen configuration to increase the heat
transfer area and hence the heat exchange effectiveness.
[0079] Other heat transfer enhancement techniques may be exploited
in the manufacture of the PCM. For example, composites may be
developed based on the PCM to advantageously improve the latent
heat of fusion of the packaged PCM. This is analogous to composites
that have been developed based on paraffins such as
styrene-butadiene-styrene triblock copolymer. Further, a small
fraction of other materials such as carbon fibers may be dispersed
in the PCM to enhance the thermal conductivity of the TES. For this
application, a high thermal conductivity is not a primary
requirement, unlike the typical Thermal Energy Storage system
(where there may be sufficient energy stored but insufficient
capacity to dispose of the energy quickly enough): there is enough
flexibility in this application, to design a system optimized
around the thermal conductivity value of the PCM.
Examples
[0080] Although optimal solutions and selection of high heat
capacity materials will depend on the composition of gas, flow
rate, temperature range, and other factors, the following is one
exemplary combination of materials arranged as a series of
phase-change materials (PCMs) stacked sequentially in a regenerator
matrix 601 based on a phase transition temperature of the PCMs. In
this exemplary embodiment, six materials are used with dividing
walls between them. Table 1 below shows the list of materials with
each material's heat of fusion (hfs), temperature of fusion (Tfs),
specific heat capacity (Cp), mass and change in enthalpy (dH). FIG.
8 is an illustration of the arrangement of the materials shown in
Table 1 with respect to the fluid flow paths and temperatures of
flow streams 202 and 108, respectively.
TABLE-US-00001 TABLE 1 Exemplary materials in a series of PCMs Cp
hfs (BTU/ m dH (BTU/ Tfs Tfs lbm- (lbm/ (BTU/ Material lbm) (F.)
(K) F.) lbm) lbm) -250 116.5 2- 51.6 -226 129.7 0.517 0.24 18.5
hexanethiol 1-octene 58.7 -177 157.2 0.513 0.49 40.6 Mix1 93.47%
145.6 -131 182.6 1.115 0.23 42.7 Mix2 53.32% 144.7 -93 203.9 1.065
0.27 49.8 Mix3 38.06% 144.4 -55 225.1 1.047 0.30 58.1 Mix4 17.00%
144.0 -8 250.9 1.021 0.28 60.2 61 289.1 SUM 1.81 270
[0081] In the example set forth in Table 1, the temperature
increase in each PCM is limited to the phase transition temperature
of the adjacent PCM for illustrative purposes only. The total mass
of the TES material required may be reduced to 1.21 from 1.81 by
allowing each PCM to warm up to the highest process temperature.
Further, the required mass may be reduced to about 0.65 by using
only the exemplary high heat capacity material Mix2 to span the
whole temperature range.
[0082] In another example, an ammonia-water binary system (mixture)
may be utilized with the shell and tube arrangement 620, 640, or
660. Such an exemplary TES material would be expected to have an
hfs of 146 BTU/lbm a Tfs of -103.degree. F., a hfg of 589 BTU/lbm,
a Tfg of -28.degree. F. and a Cp of 1.123 BTU/lbm-F and a mass
ratio of about 0.27 lbm/lbm.
[0083] While the present techniques of the invention may be
susceptible to various modifications and alternative forms, the
exemplary embodiments discussed above have been shown only by way
of example. However, it should again be understood that the
invention is not intended to be limited to the particular
embodiments disclosed herein. Indeed, the present techniques of the
invention include all alternatives, modifications, and equivalents
falling within the true spirit and scope of the invention as
defined by the following appended claims.
* * * * *