U.S. patent application number 14/182035 was filed with the patent office on 2014-09-04 for regasification plant.
The applicant listed for this patent is Lalit K. Bohra, Sulabh K. Dhanuka, O. Angus Sites. Invention is credited to Lalit K. Bohra, Sulabh K. Dhanuka, O. Angus Sites.
Application Number | 20140245779 14/182035 |
Document ID | / |
Family ID | 50190817 |
Filed Date | 2014-09-04 |
United States Patent
Application |
20140245779 |
Kind Code |
A1 |
Bohra; Lalit K. ; et
al. |
September 4, 2014 |
Regasification Plant
Abstract
Methods and system are provided for regasifying liquefied
natural gas (LNG). An exemplary method disclosed includes flowing
at least a portion of an LNG stream through an air separation unit
(ASU) to form at least a portion of a natural gas (NG) stream. Heat
is removed from an airflow in the ASU to separate an oxygen stream
from the airflow. The oxygen stream and a fuel stream are combusted
in a power plant.
Inventors: |
Bohra; Lalit K.; (Houston,
TX) ; Sites; O. Angus; (Spring, TX) ; Dhanuka;
Sulabh K.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Bohra; Lalit K.
Sites; O. Angus
Dhanuka; Sulabh K. |
Houston
Spring
Houston |
TX
TX
TX |
US
US
US |
|
|
Family ID: |
50190817 |
Appl. No.: |
14/182035 |
Filed: |
February 17, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61772435 |
Mar 4, 2013 |
|
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Current U.S.
Class: |
62/611 |
Current CPC
Class: |
F25J 1/0221 20130101;
F25J 1/0027 20130101; F25J 2210/62 20130101; F25J 2260/80 20130101;
F25J 3/04157 20130101; F25J 3/04527 20130101; F25J 3/0409 20130101;
F25J 3/04266 20130101; F25J 3/04412 20130101; F25J 1/0015 20130101;
F25J 3/04303 20130101 |
Class at
Publication: |
62/611 |
International
Class: |
F25J 1/00 20060101
F25J001/00 |
Claims
1. A method for regasifying liquefied natural gas (LNG),
comprising: flowing at least a portion of an LNG stream through an
air separation unit (ASU) to form at least a portion of a natural
gas (NG) stream; removing heat from an airflow in the ASU to
separate an oxygen stream from the airflow; and combusting the
oxygen stream and a fuel stream in a power plant.
2. The method of claim 1, comprising: flowing a portion of the LNG
stream through a gaseous carbon dioxide (CO.sub.2) chiller to form
a portion of the NG stream; and forming a liquefied CO.sub.2 stream
in the CO.sub.2 chiller.
3. The method of claim 1, comprising: flowing a portion of the LNG
stream through a nitrogen (N.sub.2) chiller to form a portion of
the NG stream; and forming a liquefied N.sub.2 stream in the
N.sub.2 chiller.
4. The method of claim 1, comprising providing the NG stream to a
market.
5. The method of claim 1, comprising: generating electrical power
in the power plant; and providing the electrical power to a
market.
6. The method of claim 2, comprising providing the liquefied
CO.sub.2 stream to a market.
7. The method of claim 1, comprising injecting the CO.sub.2 stream
into a subterranean formation.
8. The method of claim 1, comprising injecting the CO.sub.2 stream
proximate to a seabed.
9. The method of claim 1, comprising venting a nitrogen stream to
the atmosphere.
10. The method of claim 1, comprising chilling the oxygen stream
with LNG prior to the power plant.
11. A system for regasifying liquefied natural gas, comprising: an
air separation unit configured to utilize cold from a portion of a
stream of liquefied natural gas (LNG) to cryogenically distill an
air stream to produce an oxygen stream and a nitrogen stream,
forming a natural gas (NG) stream; and a power plant configured to
combust the oxygen stream with a fuel stream.
12. The system of claim 11, comprising a cold box configured to
condense liquid CO.sub.2 from an exhaust stream of the power plant
by transferring heat to a portion of the stream of LNG.
13. The system of claim 11, wherein the power plant comprises a
combined cycle power plant, comprising a gas turbine generator and
a heat recovery steam generator.
14. The system of claim 11, further comprising an inlet air cooler
on a gas turbine engine configured to transfer heat from an oxygen
stream to an LNG stream.
15. The system of claim 11, comprising an electrical generator.
16. The system of claim 11, wherein the power plant comprises a
steam generator, a steam turbine generator, a steam condenser, and
a recirculation pump.
17. A method for cryogenically distilling a gas mixture,
comprising: compressing the gas mixture; flowing the gas mixture
through a chiller to cool the gas mixture and liquefy at least a
portion of the gas mixture; flowing a liquefied natural gas through
the chiller from the gas mixture to remove heat from the gas
mixture; flowing the cooled gas mixture into a cryogenic separation
column; removing a product gas mixture from an upper section of the
cryogenic separation column; and removing a product liquid from a
lower section of the cryogenic separation column.
18. The method of claim 17, comprising purifying the gas mixture
after compression to remove carbon dioxide and water vapor.
19. The method of claim 17, comprising liquefying the product
gas.
20. The method of claim 17, comprising regasifying the product
liquid.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefit of U.S. patent
application Ser. No. 61/772,435 filed Mar. 4, 2013 entitled
REGASIFICATION PLANT, the entirety of which is incorporated by
reference herein.
FIELD OF THE INVENTION
[0002] Exemplary embodiments of the present techniques relate to a
liquefied natural gas terminal with flexible capability to provide
pipelined natural gas, electricity to a grid, or both.
BACKGROUND
[0003] Large volumes of natural gas (i.e., primarily methane) are
located in remote areas of the world. This gas has significant
value if it can be economically transported to market. Where the
gas reserves are located in reasonable proximity to a market and
the terrain between the two locations permits, the gas is typically
produced and then transported to market through submerged and/or
land-based pipelines. However, when gas is produced in locations
where laying a pipeline is infeasible or economically prohibitive,
other techniques must be used for getting this gas to market.
[0004] A commonly used technique for non-pipeline transport of gas
involves liquefying the gas at or near the production site and then
transporting the liquefied natural gas to market in
specially-designed storage tanks aboard transport vessels. The
natural gas is cooled and condensed to a liquid state to produce
liquefied natural gas ("LNG"). LNG is often transported at
substantially atmospheric pressure and at temperatures of about
-162.degree. C. (-260.degree. F.), thereby significantly increasing
the amount of gas which can be stored in a particular storage tank
on a transport vessel. Once a LNG transport vessel reaches its
destination, the LNG is typically off-loaded into other storage
tanks from which the LNG can then be revaporized as needed and
transported as a gas to end users through pipelines or the like.
Natural gas is used for various purposes one of them being power
generation. LNG has been an increasingly popular transportation
method to supply major energy-consuming nations with natural
gas.
[0005] During the regasification process, natural gas temperature
changes from about -162.degree. C. to up to about 15.degree. C.
depending on sales specification. Required heat for regasification
is typically supplied by burning some of the product natural gas in
fuel-fired vaporizers such as Submerged Combustion Vaporizers
(SCVs) or Shell-and-Tube Vaporizers (STVs) with Fired Heaters.
These fuel-fired vaporizers consume about 1.5-2.0% of product
natural gas as the fuel. The fuel consumption not only results in
large operating expenses by consuming some of the product itself
but also in large environmental emissions in the form of CO.sub.2
and NO.sub.R. Using other sources of heat such as sea water and
ambient air may reduce the terminal emissions but these have their
own limitations. For example, use of sea water requires large
capital investment and may adversely affect marine life due to the
very large quantities of sea water required and the cold
temperature of the discharge. At many locations, it is almost
impossible to obtain permit to use sea water from regulatory
authorities. Use of ambient air heat may be a viable option only in
hot climates; even there benefit is greatly reduced by daily and
seasonal variation in temperature and humidity.
[0006] The general methods discussed above utilize various heat
sources to capture the cold contained in LNG, which could be used
for reducing emissions, improving process efficiencies and
economics of the LNG receiving terminal Therefore, research efforts
have focused on finding methods that not only reduce fuel
consumption thereby reducing operating expenses and emissions
associated with LNG regasification process, for example, by
utilizing the LNG cold.
[0007] Several methods have been proposed in the prior art to
address the issues of reducing emissions, and to use LNG cold to
some advantage. One such method includes integrating LNG
regasification with power generation. One efficient power
generation method is the combined cycle power plant (CCGT). A CCGT
plant includes gas turbine generator (GTG), which may further
include compressors, combustors, gas turbines (GT), and the like. A
heat recovery unit (HRU) can then be used to recover the exhaust
heat from the gas turbine. An example of an HRU is a heat recovery
steam generator (HRSG). The
[0008] HRSG uses exhaust heat from the GTs for steam generation,
and then sends the steam through a steam turbine generator (STG),
and steam condenser. The steam condenser may use cooling from the
LNG regasification for the condensation. Further, CCGT can include
a cooling tower to provide coolant to a steam condenser.
[0009] The use of LNG cold to cool the inlet air in a gas turbine
based power plant or condensing steam exiting steam turbine from a
combined cycle power plant has been disclosed in the art. For
example, U.S. Patent Application Publication No. 2008/0190106, by
Mak, discloses power generation integrated with LNG regasification.
The cold from the LNG is used in a combined power plant to increase
power output. In configurations, a first stage LNG cold provides
cooling to an open or closed power cycle. A portion of the LNG is
vaporized in the first stage. In a second stage, the cold from the
LNG provides cooling for a heat transfer medium that is used to
provide refrigeration for the cooling water to a steam power
turbine and for an air intake chiller of a combustion turbine in
the power plant.
[0010] U.S. Patent Application Publication No. 2005/0223712 by
Briesch, et al., discloses using the vaporization of LNG to
increase efficiency in power cycles. Inlet air chilling for a gas
turbine is provided by the vaporization of the LNG. The cycle uses
regeneration for preheating of combustor air. The process offers
the potential efficiencies for the gas turbine cycle in excess of
60%. The systems and methods permit the vaporization of LNG using
ambient air, with the resulting super cooled air being easier to
compress. In alternative embodiments, the vaporization of the LNG
may be used as part of a bottoming cycle to increase the
efficiencies of the gas turbine system.
[0011] U.S. Patent Application Publication No. 2003/0005698 by
Keller discloses a process and system for LNG regasification. The
system for vaporizing the LNG utilizes the residual cooling
capacity of the LNG to condense the working fluid of a power
producing cycle. The LNG can also chill liquids that are used in a
direct-contact heat transfer system to cool air. The cold air is
used to supply air to a combustion gas turbine operating in
conjunction with a combined cycle power plant.
[0012] U.S. Pat. No. 6,367,258 to Wen, et al., discloses vaporizing
LNG in a combined cycle power plant. The efficiency of the combined
cycle generation plant can be increased by using the vaporization
of cold liquid including liquefied natural gas ("LNG") or liquefied
petroleum gas (LPG). The vaporization is assisted by circulating a
warm heat transfer fluid to transfer heat to a LNG/LPG vaporizer.
The heat transfer fluid is chilled by LNG/LPG cold liquid
vaporization and warmed by heat from a gas turbine. The heat
transfer fluid absorbs heat from the air intake of a gas turbine
and from a secondary heat transfer fluid circulating in a combined
cycle power plant.
[0013] There is potential to eliminate fuel consumption associated
with LNG regasification if a large enough power plant could be
installed at the LNG regasification location. This scheme also
improves efficiency of the power plant and the power output by
cooling the turbine inlet air and providing a colder cooling medium
to the steam turbine condenser. LNG cold may also be used in the
intercoolers for the compressor of the GTG.
[0014] Another method to reduce emissions from a LNG terminal is
use of ambient air heat for LNG regasification. Since use of
ambient air heat reduces fuel consumption, the terminal economics
may improve considerably. There are multiple types of ambient air
vaporizers, including, for example, a direct type (both natural and
forced draft), a fin-fan (similar to air coolers), and a warming
tower (also known as a "reverse cooling tower" or "heating tower").
The use of a warming tower has been described in prior art for LNG
regasification.
[0015] For example, U.S. Pat. No. 6,644,041, to Eyermann, discloses
the vaporization of liquefied natural gas using a water tower. A
temperature of a water stream may be increased in the water tower.
The warmed water can be passed through a first heat exchanger, and
a circulating fluid may also be passed through the first heat
exchanger so as to transfer heat from the warmed water into the
circulating fluid. The LNG may be passed into a second heat
exchanger, and the heated circulating fluid from the first heat
exchanger may be passed through the second heat exchanger so as to
transfer heat from the circulating fluid to the LNG gas. The
vaporized natural gas is discharged from the second heat
exchanger.
[0016] Further, U.S. Pat. No. 7,137,623 to Mockry, et al.,
discloses a heating tower that isolates outlet and inlet air. The
heating tower may be used to heat a fluid by drawing an air stream
into the heating tower through an inlet and passing the air stream
over a fill medium. A fluid is passed over the fill medium along
with discharging the air stream from the heating tower through an
outlet. The method further includes isolating the inlet air stream
from the outlet air stream.
[0017] In the techniques discussed above, a power plant integrated
with a LNG regasification process can decrease emissions and
utilize LNG cold, while use of a warming tower for LNG
regasification addresses only emissions issue. However, the size of
a power plant will be very large to fully utilize the cold from the
LNG. For example, for 2 BCFD (billion cubic feet per day) of
natural gas sales may require that the power plant be around 500 MW
to utilize the cold. This size of plant would represent a very
large capital expenditure. Further, a large market would be needed
for the electricity produced by the plant.
[0018] Both the power plant and warming tower options become less
attractive if there is not enough demand for natural gas, which may
occur seasonally. Less demand for natural gas means there is less
cold available from the LNG. Less available cold reduces the
operational efficiency of installed equipment. The use of a warming
tower can be further constrained by prevailing ambient conditions,
such as temperature and humidity. Therefore, both of the above
mentioned techniques provide only partial solutions without any
flexibility in utilizing LNG cold.
[0019] Related information may be found in U.S. Pat. Nos.
5,295,350; 5,457,951; 6,324,867; 6,367,258; 6,374,591; 7,299,619;
and 7,644,573. Further information may also be found in U.S. Patent
Application Publication Nos. 2003/0005698, 2008/0307789,
2008/0034727, 2008/0047280, 2008/0178611, 2008/0190106,
2008/0250795, 2008/0276617, and 2008/0307789. Further information
may also be found in Rosetta, M. J., and Himmelberger, "Integrating
Ambient Air Vaporization Technology with Waste Heat Recovery--A
Fresh Approach to LNG Vaporization," presented at the 85.sup.th
annual convention of the Gas Processors of America (GPA 2006),
Grapevine, Tex., Mar. 5-8, 2006; Cho, J. H.; Ebbern, D., Kotzot,
H., and Durr, C., "Marrying LNG and Power Generation," Energy
Markets; October/November 2005; 10, 8; ABI/INFORM Trade &
Industry, p. 28; Rajeev Nanda and John Rizopoulos, "Utilizing Air
Based Technologies as Heat Source for LNG Vaporization," presented
at the 86th Annual convention of the Gas Processors of America (GPA
2007), Mar. 11-14, 2007, San Antonio, Tex.
SUMMARY
[0020] An embodiment disclosed herein provides a method for
regasifying liquefied natural gas (LNG). The method includes
flowing at least a portion of an LNG stream through an air
separation unit (ASU) to form at least a portion of a natural gas
(NG) stream. Heat is removed from an airflow in the ASU to separate
an oxygen stream from the airflow. The oxygen stream and a fuel
stream are combusted in a power plant.
[0021] Another embodiment provides a system for regasifying
liquefied natural gas. The system includes an air separation unit
configured to utilize cold from a portion of a stream of liquefied
natural gas (LNG) to cryogenically distill an air stream to produce
an oxygen stream and a nitrogen stream, forming a natural gas (NG)
stream. The system also includes a power plant configured to
combust the oxygen stream with a fuel stream.
[0022] Another embodiment provides a method for cryogenically
distilling a gas mixture. The method includes compressing the gas
mixture and flowing the gas mixture through a chiller to cool the
gas mixture and liquefy at least a portion of the gas mixture. A
liquefied natural gas is flowed through the chiller from the gas
mixture to remove heat from the gas mixture. The cooled gas mixture
is flowed into a cryogenic separation column. A product gas mixture
is removed from an upper section of the cryogenic separation
column. A product liquid is removed from a lower section of the
cryogenic separation column.
BRIEF DESCRIPTION OF THE DRAWINGS
[0023] The advantages of the present techniques are better
understood by referring to the following detailed description and
the attached drawings, in which:
[0024] FIG. 1 is a block diagram of a LNG terminal that
incorporates a power plant, illustrating the use of cold from the
LNG to purify an air stream for use in the power plant;
[0025] FIG. 2 is a block diagram of another LNG terminal that
incorporates a power plant, illustrating the use of cold from the
LNG to liquefy product stream for sale;
[0026] FIG. 3 is a process flow diagram of a LNG regasification
method that can be used in the systems discussed above;
[0027] FIG. 4 is a simplified process flow diagram of a combined
plant having an ASU that provides LNG regasification and a power
plant that combusts fuel with oxygen generated in the ASU;
[0028] FIG. 5 is a simplified process flow diagram of a combined
plant having an ASU that provides LNG regasification and a power
plant that combusts fuel with oxygen generated in the ASU;
[0029] FIG. 6 is a simplified process flow diagram of an air
separation unit (ASU) that may be used in embodiments; and
[0030] FIGS. 7A and 7B are a simplified process flow diagram of a
power plant that can be used in embodiments.
DETAILED DESCRIPTION
[0031] In the following detailed description section, specific
embodiments of the present techniques are described. 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 techniques are not limited to the specific
embodiments described below, but rather, include all alternatives,
modifications, and equivalents falling within the true spirit and
scope of the appended claims.
[0032] At the outset, for ease of reference, certain terms used in
this application and their meanings as used in this context are set
forth. To the extent a term used herein is not defined below, it
should be given the broadest definition persons in the pertinent
art have given that term as reflected in at least one printed
publication or issued patent. Further, the present techniques are
not limited by the usage of the terms shown below, as all
equivalents, synonyms, new developments, and terms or techniques
that serve the same or a similar purpose are considered to be
within the scope of the present claims.
[0033] A "combined cycle power plant" includes a gas turbine, a
steam turbine, a generator, and a heat recovery steam generator
(HRSG), and uses both steam and gas turbines to generate power. The
gas turbine operates in an open Brayton cycle, and the steam
turbine operates in a Rankine cycle. Typically, combined cycle
power plants utilize heat from the gas turbine exhaust to boil
water in a heat recovery unit (HRU) to generate steam. The steam
generated is utilized to power the steam turbine. After powering
the steam turbine, the steam may be condensed and the resulting
water returned to the HRU. The gas turbine and the steam turbine
can be utilized to separately power independent generators, or in
the alternative, the steam turbine can be combined with the gas
turbine to jointly drive a single generator via a common drive
shaft. These combined cycle gas/steam power plants generally have
higher energy conversion efficiency than gas or steam only plants.
A combined cycle plant's efficiencies can be as high as 50% to 60%.
The higher combined cycle efficiencies result from synergistic
utilization of a combination of the gas turbine with the steam
turbine.
[0034] As used herein, a "cryogenic fluid" includes any fluid with
a boiling point of less than about -130.degree. C. at ambient
pressure conditions. Such fluids may include liquefied natural gas
(LNG), liquid nitrogen, liquid oxygen, liquid hydrogen, liquid
helium, liquid carbon dioxide, and the like.
[0035] A "fuel" includes any number of hydrocarbons that may be
combusted with an oxidant to power a gas turbine. Such hydrocarbons
may include natural gas, treated natural gas, kerosene, gasoline,
or any number of other natural or synthetic hydrocarbons. In one
embodiment, natural gas from an oil field is purified and used to
power the turbine. In another embodiment, a reformed gas, for
example, created by processing a hydrocarbon in a steam reforming
process may be used to power the turbine.
[0036] The term "gas" is used interchangeably with "vapor," and
means a substance or mixture of substances in the gaseous state as
distinguished from the liquid or solid state. Likewise, the term
"liquid" means a substance or mixture of substances in the liquid
state as distinguished from the gas or solid state.
[0037] A "heat exchanger" broadly means any device capable of
transferring heat from one media to another media, including
particularly any structure, e.g., device commonly referred to as a
heat exchanger. Heat exchangers include "direct heat exchangers"
and "indirect heat exchangers." Thus, a heat exchanger may be a
plate-and-frame, shell-and-tube, spiral, hairpin, core,
core-and-kettle, double-pipe, or any other type of known heat
exchanger.
[0038] "Heat exchanger" may also refer to any column, tower, unit
or other arrangement adapted to allow the passage of one or more
streams therethrough, and to affect direct or indirect heat
exchange between one or more lines of refrigerant, and one or more
feed streams.
[0039] A "hydrocarbon" is an organic compound that primarily
includes the elements hydrogen and carbon although nitrogen,
sulfur, oxygen, metals, or any number of other elements may be
present in small amounts. As used herein, hydrocarbons generally
refer to organic materials that are harvested from hydrocarbon
containing sub-surface rock layers, termed reservoirs. For example,
natural gas is a hydrocarbon.
[0040] "Liquefied natural gas" or "LNG" is cryogenic liquid form of
natural gas generally known to include a high percentage of
methane, but also other elements and/or compounds including, but
not limited to, ethane, propane, butane, carbon dioxide, nitrogen,
helium, hydrogen sulfide, or combinations thereof. The natural gas
may have been processed to remove one or more components (for
instance, helium) or impurities (for instance, water and/or heavy
hydrocarbons) and then condensed into the liquid at almost
atmospheric pressure by cooling.
[0041] The term "natural gas" refers to a multi-component gas
obtained from a crude oil well (associated gas) or from a
subterranean gas-bearing formation (non-associated gas). The
composition and pressure of natural gas can vary significantly. A
typical natural gas stream contains methane (C.sub.1) as a
significant component. Raw natural gas may also contain ethane
(C.sub.2), higher molecular weight hydrocarbons, acid gases (such
as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon
disulfide, and mercaptans), and minor amounts of contaminants such
as water, nitrogen, iron sulfide, wax, and crude oil. As used
herein, natural gas includes gas resulting from the regasification
of a liquefied natural gas, which has been purified prior to
liquefaction to remove contaminates, such as water, acid gases, and
most of the higher molecular weight hydrocarbons.
[0042] As used herein, a "Rankine power plant" includes a steam
generator, a steam turbine, a steam condenser, and a recirculation
pump. The steam generator is often a gas fired boiler that boils
water to generate the steam. However, in embodiments, the steam
generator may be a heat recovery unit configured to boil water from
the heat in an exhaust stream from a gas turbine engine. The steam
is used to generate electricity in the steam turbine generator, and
the reduced pressure steam is then condensed in the steam
condenser. The resulting water is recirculated to the steam
generator to complete the loop.
[0043] "Substantial" when used in reference to a quantity or amount
of a material, or a specific characteristic thereof, refers to an
amount that is sufficient to provide an effect that the material or
characteristic was intended to provide. The exact degree of
deviation allowable may in some cases depend on the specific
context.
Overview
[0044] Embodiments described herein provide liquid natural gas
(LNG) regasification techniques and systems that reduce emissions
associated with fuel-fired vaporizers and improve the flexibility
of utilizing LNG cold. In an embodiment, LNG is regasified using
heat obtained from cooling an air flow in an air separation unit
(ASU) to create an oxygen stream. The oxygen stream is used in a
power plant to combust a fuel.
[0045] FIG. 1 is a block diagram of a LNG terminal 100 that
incorporates a power plant, illustrating the use of cold from the
LNG to purify an air stream for use in the power plant. In the LNG
terminal 100, purified air 102 is passed through an air separation
unit (ASU) 104 to separate oxygen 106 and nitrogen 108 from the
purified air 102, as discussed with respect to FIG. 6. The ASU 104
utilizes a cryogenic distillation process. The cold is provided by
a stream of LNG 110. As the LNG 110 removes heat energy from the
air 102, it is regasified into the product natural gas (NG) 112. A
portion of the NG 112 can be used as a fuel for the power plant
114, adding to the efficiency of the process.
[0046] The oxygen 106 is used to provide oxidant to the power plant
114, which may be, for example, a combined cycle power plant
utilizing a gas turbine generator and a heat recovery steam
generator (HRSG), as discussed with respect to FIG. 7. In some
embodiments, the power plant 114 may be a Rankine cycle power plant
using a standard boiler and steam generator configuration. The
power plant 114 can be used to generate power 116 for the LNG
terminal 100. The power 116 may include mechanical energy, for
example, to power compressors in the LNG terminal 100. The power
116 may also include electrical power, either consumed in the LNG
terminal 100, marketed through an electrical grid, or both. The
exhaust from the power plant 114 can be purified to form carbon
dioxide (CO.sub.2) 118, which can be used in enhanced oil recovery,
sold as a product, or both. The purification of the CO.sub.2 118
may be performed by passing the exhaust from the power plant 114
through a cooler to condense out water vapor formed in the
combustion process. As the combustion is fed substantially pure
oxygen, little, if any, nitrogen oxides, or other combustion
by-products will be formed.
[0047] FIG. 2 is a block diagram of another LNG terminal 200 that
incorporates a power plant, illustrating the use of cold from the
LNG to liquefy product stream for sale. Like numbered items are as
described with respect to FIG. 1. In embodiments, the CO.sub.2 118
can be liquefied using the LNG 110 as a heat sink in a CO.sub.2
chiller 202. This will also add to the amount of NG 112 available
for sales. The liquefied CO.sub.2 204 can then be provided for
sale. Further, the N.sub.2 108 can be liquefied using the LNG 110
as a heat sink in an N.sub.2 chiller 206. The liquefied N.sub.2 208
can also be sold.
[0048] FIG. 3 is a process flow diagram of a LNG regasification
method 300 that can be used in the systems discussed above. The
method begins at block 302, with the use of LNG in an ASU to obtain
O.sub.2 and N.sub.2 from a purified air stream. At block 304, at
least a portion of the resulting NG can be sold, for example, to a
pipeline. At block 306, the N.sub.2 can be sold or vented,
depending on the economics of the N.sub.2 as a product. In an
embodiment, the cold from the LNG is used to condense the nitrogen
for sales as a liquid product.
[0049] If the nitrogen is vented, it may be passed through an
expander to produce mechanical energy prior to venting. The
mechanical energy can be used to drive a generator, producing
electricity. Further, after the expander, the nitrogen will be
substantial cooler and may be used for cooling other units and
processes.
[0050] At block 308, the oxygen from the ASU is provided to the
combustors, or burners, in a power plant. Substantially
simultaneously, at block 310, a fuel is provided to the combustors
or burners in the power plant. The fuel may be a portion of the NG
generated from the regasification of the LNG. However, the power
plant is not limited to using the NG as the fuel. For example, if
the LNG terminal is built in proximity to an existing power plant,
substantial synergies can be obtained by providing oxygen to the
power plant, decreasing emissions from the combustion of the fuel
without changing the configuration of the power plant to use the
natural gas.
[0051] At block 312, the fuel and oxygen are combusted in the power
plant, producing power at block 314. The power can be mechanical
power, for example, used to power compressors or an electrical
generator. At block 316, at least a portion of the electrical power
generated may be marketed. This may be in addition to any power
that is used in the plant itself.
[0052] At block 318, the CO.sub.2 from the exhaust stream may be
condensed to a liquid. At block 320, the NG produced may be
marketed, for example, being combined with the NG streams produced
from the ASU and any nitrogen condenser used. At block 322, the
CO.sub.2 is marketed or used, for example, for enhanced oil
recovery. In some embodiments, the CO.sub.2 may be disposed, or
sequestered, by injection into subterranean formations. Other
sequestration sinks may include injection of the CO.sub.2 into a
seabed at a temperature and pressure that is sufficient to keep the
CO.sub.2 in liquid form.
Examples of Combined LNG Terminal and Power Plant Equipment
[0053] FIG. 4 is a simplified process flow diagram of a combined
plant 400 having an ASU that provides LNG regasification and a
power plant that combusts fuel with oxygen generated in the ASU.
Like numbered items are as described with respect to FIGS. 1 and 2.
In the combined plant 400, an LNG high pressure pump 402 boosts the
pressure of the LNG 110 to the pipeline pressure for marketing the
NG 112, prior to the use of the high pressure LNG 403 in the ASU
104 and other chillers, such as the CO.sub.2 chiller 202.
[0054] To purify the CO.sub.2 for condensation, the exhaust 404
from the power plant 114 is passed through a cooler 406. In the
cooler 406, the exhaust 404 may be cooled or chilled by a heat
exchange solution 408, such as water, a glycol/water mixture,
ammonia, and the like. The heat exchange solution 408 may be cooled
by exchanging heat with a portion of the high pressure LNG 403, or
may be cooled by a standard refrigeration procedure. The chilled
exhaust stream 410 is flowed into a separator in which the water
414 settles out from the bottom, and the dry CO.sub.2 118 flows out
the top. After drying, the CO.sub.2 118 may have a dewpoint of
-10.degree. C., -20.degree. C., -40.degree. C., or lower. If a
lower dewpoint is desired, the CO.sub.2 118 may be flowed through a
second heat exchanger, which may be chilled by a portion of the
high pressure LNG stream 403. After drying, the CO.sub.2 118 is
flowed into a compressor 416 to boost the pressure to a point at
which liquid CO.sub.2 118 will form, e.g., greater than about 517
kPa. The high pressure CO.sub.2 418 is then flowed into the
CO.sub.2 chiller 202 to be cooled against the high pressure LNG
403.
[0055] In the CO.sub.2 chiller 202, the high pressure CO.sub.2 418
is liquefied. The liquefied CO.sub.2 204 can then be used, sold, or
disposed of, for example, by injection into a subterranean
formation.
[0056] FIG. 5 is a simplified process flow diagram of a combined
plant 500 having an ASU that provides LNG regasification and a
power plant that combusts fuel with oxygen generated in the ASU.
Like number items are as described with respect to previous
figures. As noted herein, the N.sub.2 108 may be liquefied for
marketing. In the combined plant 500, the N.sub.2 108 is passed
through an N.sub.2 liquefier 502 to perform this function. The
N.sub.2 liquefier 502 can include a compressor to increase the
pressure of the N.sub.2 108, followed by a chiller to liquefy the
high pressure nitrogen. In other embodiments, the N.sub.2 can be
flowed directly through a chiller to be condensed into the liquid
N.sub.2 208. The liquid N.sub.2 208 can then be marketed.
[0057] FIG. 6 is a simplified process flow diagram of an air
separation unit (ASU) 600 that may be used in embodiments. Like
numbered items are as discussed with respect to the previous
figures. The ASU 600 can be used, for example, as the ASU 104
discussed with respect to FIG. 1. In the ASU 600, purified air 102
is passed through a compressor 602 to increase the pressure for
processing. The compressed air 604 is flowed through a pre-cooler
606 to remove the heat of compression and reduce the temperature
for the distillation process. The pre-cooler 606 may be chilled
with a stream of LNG 110, which can add to the amount of NG 112
formed in the regasification plant. The chilled air stream 608 can
be flowed through a purification unit 610, which can be used to
remove any remaining CO.sub.2, water, or both from the air prior to
the cryogenic distillation.
[0058] The process feed stream 612 is sent through a main heat
exchanger 614 for initial chilling to cryogenic temperatures, e.g.,
less than the boiling point for oxygen (about -183.degree. C., at
atmospheric pressure) and greater than the boiling point for
nitrogen (about -195.8.degree. C., at atmospheric pressure). It
will be understood that these temperatures will increase at higher
pressures. However, the temperature of the oxygen liquefaction
increases at a higher rate than the nitrogen, broadening the
operating range for the cryogenic distillation at higher
pressures.
[0059] In an embodiment, the main heat exchanger 614 is chilled by
a stream of LNG 110. As the LNG 110 vaporizes in the main heat
exchanger, NG 112 is formed. This decreases or eliminates the need
to provide extra cooling to the main heat exchanger 614, and
increases the overall efficiency of the process. The main heat
exchanger can be an aluminum fin type generally used in cryogenic
cold boxes. However, other types may be used, such as shell/tube
heat exchangers, plate type heat exchangers, and plate-fin heat
exchangers, among others.
[0060] A portion of the feed stream 612 may be sent through a boost
compressor 615 to further increase the pressure. The high pressure
stream 616 from the boost compressor 614 is flowed through the main
heat exchanger 614 for chilling. The chilled high-pressure stream
618 is passed through an expander 620 which further removes energy,
forming a mixed phase stream 622. The mixed phase stream 622 is
passed through a subcooler 624, and then injected into a low
pressure distillation column 626.
[0061] Another portion of the feed stream 612 is passed directly
through the main heat exchanger 614 for chilling. The chilled feed
stream 628 is injected into a high pressure distillation column
630. The low pressure distillation column 626 and the high pressure
distillation column 630 may be different regions of a single
column, for example, with a plate 632 that isolates the two
pressure regions.
[0062] A liquid bottoms stream 634 is taken from the bottom of the
high pressure distillation column 630 and passed through the
sub-cooler 624. The liquid bottoms stream 634 is flashed across a
valve 636 before being injected into the low pressure distillation
column 626. The flashing of the liquid bottoms stream 634 further
decreases the temperature of the stream and allowing separation of
liquid and gas phases in the low pressure distillation column 626.
A gas top stream 638 is removed from the top of the high pressure
distillation column 630, and is passed through the sub-cooler 624,
before being injected into the low pressure distillation column
626.
[0063] A liquid oxygen stream 640 is taken from the bottom of the
low pressure distillation column 626. The liquid oxygen stream 640
can be pumped through the main heat exchanger 614 to be regasified
to oxygen 106, prior to being sent on to the power plant. A gas
nitrogen stream 642 can be taken from the top of the low pressure
distillation column 626. The nitrogen stream 642 can be disposed,
for example, by passing the gas through an expander to remove
energy and then venting. In an embodiment, the nitrogen is
liquefied using the cold from a stream of LNG 110, further
increasing the amount of NG 112 that can be produced.
[0064] The ASU 600 is not limited to the configuration shown. Any
number of other configurations, including, for example, single
columns, high pressure chilling, and the like may be used for
cryogenic distillation in embodiments.
[0065] FIGS. 7A and 7B are a simplified process flow diagram of a
power plant 700 that can be used in embodiments. The power plant
700 illustrated is a combined cycle power plant using a gas turbine
engine 702 and a heat recovery steam generator (HRSG) 704. An ASU
104 using LNG to provide cooling may be used to provide oxygen 116
to the gas turbine engine 702, as described herein. It can be noted
that the present techniques are not limited to combined cycle power
plants, but may also be used with power plants based on other power
generation cycles, such as a steam power plant based on a Rankine
cycle.
[0066] The gas turbine engine 702 may have a compressor 706 and a
turbine expander 708 on a single shaft 710. The gas turbine engine
702 is not limited to a single shaft arrangement, as multiple
shafts could be used, generally with mechanical linkages or
transmissions between shafts. The gas turbine engine 702 may also
have a number of combustors 712 that feed hot exhaust gas 714 to
the turbine expander 708. For example, the gas turbine engine 702
may have 2, 4, 6, 14, 18, or even more combustors 712, depending on
the size of the gas turbine engine 702.
[0067] The combustors 712 are used to burn a fuel 716, for example,
a portion of the NG 112 stream regasified from an LNG 110, as
discussed with respect to FIG. 1. Oxygen 116 from an ASU 104 may be
provided to each of the combustors 712. Recycled exhaust gas 718
may be compressed in the compressor 706 and then provided to the
combustors 712 for cooling and dilution of the fuel and oxygen
mixture.
[0068] The exhaust gas 714 from the combustors 712 expands in the
turbine expander 708, creating mechanical energy. The mechanical
energy may power the compressor 706 through the shaft 710. Further,
a portion of the mechanical energy may be used to power an
electrical generator 720 or additional compressors. The oxygen 116
flow can be individually metered to each of the combustors 712 to
control an equivalence ratio in that combustor 712.
[0069] It will be apparent to one of skill in the art that a
stoichiometric burn, e.g., at an equivalence ratio of 1, will be
hotter than a non-stoichiometric burn. Therefore, cooling with a
high pressure recycle gas 718 can prevent damage to the combustors
712 or the turbine expander 708 from the extreme heat. Sensors can
be placed in an expander exhaust section 722 of the gas turbine
engine 702 to control flow of the oxygen and fuel.
[0070] A control system, such as a distributed control system
(DCS), a programmable logic controller (PLC), a direct digital
controller (DDC), or any other appropriate control system, may be
used to control the operation of the LNG terminal and power plant.
For example, the control system may automatically adjust
parameters, such as the amount of LNG that can be regasified at a
particular operating rate.
[0071] In the embodiment shown in FIG. 7, the compressor 706 is
used to compress a recycled exhaust stream 724 to form the high
pressure recycle gas 718. The oxygen 116 does not have to be
separately injected, but may be mixed with the recycled exhaust
stream 724.
[0072] In the combined cycle power plant 700, the hot exhaust gases
726 from the expander exhaust section 722 are passed through a heat
recovery unit (HRU) 728. In the HRU 728, the hot exhaust gases 726
are used to boil a stream of water 730, forming steam 732. The
steam 732 is used to turn a steam turbine (ST) 734, which may be
used to power a generator 736, compressors, or other units. The low
pressure steam 738 from the steam generator 734 is condensed back
to water 730 in a heat exchanger 740, completing a Rankine
cycle.
[0073] The hot exhaust gases 726 are cooled in the HRU 728, forming
a cooled exhaust stream 742. The cooled exhaust stream 742, which
includes primarily CO.sub.2 and water vapor from the combustion, is
passed through a cooler 744, which chills the stream and condenses
out most of the water 746, forming the recycled exhaust stream
724.
[0074] The gas turbine engine 702 of the combined cycle power plant
700 can be described as operating in a semi-closed Brayton cycle.
The gas turbine engine 702 cannot operate in a fully closed Brayton
cycle since mass is introduced from the fuel and oxygen. This mass
is removed as the condensed water 746, and as an exhaust stream
748, for example, from the high pressure recycle gas 718. The
exhaust stream 748 can be provided to a chiller to form a liquid
CO.sub.2 stream, as described with respect to FIGS. 1 and 2.
[0075] The cooler 744 may be a non-contact heat exchanger, or any
number of other types described herein. For example, in an
embodiment, the cooler 744 may be a tube in shell heat exchanger,
in which a water stream is flowed through tubes inside a shell,
while the cooled exhaust stream 742 is flowed around the tubes. As
the cooled exhaust stream 742 contact the tubes, it is further
cooled, and water 746 condenses out. The water 746 can then be
removed from the shell of the cooler 744, for example, through a
weir, allowing the recycled exhaust stream 724 to flow out
separately. In this embodiment, the recycled exhaust stream 724
from the cooler 744 may then be recycled to the inlet of the
compressor 706.
[0076] In summary, embodiments described herein provide benefits
over fuel-fired vaporizers, including, for example, more efficient
use of installed equipment, such as power plants. Further, the
techniques provide increased flexibility to use cold contained in
LNG 110 and lower the amount of fuel used to vaporize LNG 110 and,
thus, increase the sales and revenue of natural gas 110 from an LNG
terminal 100. The elimination or reduction of fuel-fired vaporizers
and the use of oxygen from an ASU 104, may also decrease the
associated capital expenditures and operating expenditures, and
provide a reduction in the emissions, such as CO.sub.2 and
NO.sub.x, associated with the fuel consumption of a vaporizer in a
terminal The use of the cold from the LNG 110 also provides an
increase in power plant efficiency and power output.
[0077] While the present techniques 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 techniques is not intended to
be limited to the particular embodiments disclosed herein. Indeed,
the present techniques include all alternatives, modifications, and
equivalents falling within the true spirit and scope of the
appended claims.
* * * * *