Note: Descriptions are shown in the official language in which they were submitted.
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LNG REGASIFICATION CONFIGURATIONS AND METHODS
Field of The Invention
The field of the invention is gas processing, especially as it relates to
regasification of
liquefied natural gas for heating value control, and recovery or extraction of
C2, and C3 plus
components for sales.
Background of The Invention
As the demand for natural gas in the United States has risen sharply in recent
years,
the market price of natural gas has become increasingly volatile.
Consequently, there is a
renewed interest in import of liquefied natural gas (LNG) as an alternative
source for natural
gas. However, niost import LNG has a higher heating value and is richer in
heavier
hydrocarbons than is allowed by typical North American natural gas pipeline
specifications.
For example, while some countries generally accept the use of richer aiid high
heating value
LNG, the requirements for the North American market are driven by ecological
and
enviromnental concerns and may further depend on the particular use of the
LNG.
One of the problems with LNG import is that a substantial fraction of the
world LNG
supply is rich LNG with non-compliant heating values. As the LNG import market
grows,
spot LNG trades are becoming more common, similar to today's crude oil trade
market. With
increasing LNG trading between different LNG producers and North American
regasification
sites, LNG terminals must be configured to accept LNG with various
compositions and
heating values to reinain regulation compliant and cost'competitive. In some
markets, rich
LNG can be made profitable as its ethane content can be used for petrochemical
plant
feedstock, the propane content can be sold as LPG, and the butane plus liquid
can be used for
gasoline blending. Additionally, processing steps for extraction of the
heavier components
from the rich LNG are necessary to meet the stringent North America pipeline
heating value
specification.
In most upstream LNG liquefaction plants, removal of pentane, hexane, and
heavier
3o hydrocarbons is required only to avoid wax formation in the cryogenic
liquefaction
exchanger. The LPG coniponents (C2, C3 and C4+) are typically not removed and
are
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liquefied together with the methane component, resulting in LNG with a fairly
high gross
heating value. Exemplary heating values of LNG from a number of LNG export
plants in the
Atlantic, Pacific Ocean and Middle East LNG plants are shown in Figure S. The
higher
heating values indicate a higher proportion of the non-methane components. The
compositions of the ethane, propane, and butane and heavier components for
these LNG are
shown in Figure 9.
In North America, many pipeline operators require very lean gas for
transmission, and
in some mid-west regions, natural gas gross heating value ranges between 960
and 1050
Btu/scf. In California, the acceptable gross heating value is between 970 and
1150 Btu/scf.
California also imposes constraints on specific gas components for coinpressed
natural gas
consumption. Currently, acceptable LNG that meets the California specification
is limited to
sources such as the Kenai, Alaska LNG, or the Atlantic LNG from Trinidad.
Therefore, to
meet North American natural gas specifications, regasification terminals must
have facilities
that are capable of processing non-compliant LNG. Most commonly, LNG heating
value and
Wobbe Index are controlled by dilution with nitrogen, or blending with a
leaner natural gas.
However, there are limits on the maximum amount of nitrogen and inerts that
can be
introduced to the pipeline gas. Moreover, dilution with nitrogen often
requires an air
separation plant to produce the nitrogen, which is costly and produces no
other benefit for the
facility, and a lean gas source is often not available for blending in a
relatively large LNG
regasification facility.
As environmental regulations become more stringent, tighter control on LNG
compositions than the current specifications are expected in the North
Ainerican markets,
requiring new processes that can economically remove the C2+ components from
LNG.
Moreover, such processes should advantageously provide a plant with sufficient
flexibility to
handle a wide range of LNG allowing importers to buy LNG from various low cost
markets
instead of being limited to those sources that meet the North America
specifications.
Conventional processes for regasifying rich LNG (e.g., LNG from Indonesia is
typically at 1200 to 1300 Btu/SCF) involve heating the LNG in fuel-fired
heaters or with
seawater heaters, and then diluting the vaporized LNG with nitrogen or a lean
gas to meet the
3o heating value specification. However, either heating process is undesirable
as fuel gas heaters
generate emissions and COZ pollutants, and seawater heaters require costly
seawater systems
and also negatively impact the ocean environment. Furthermore, dilution with
nitrogen to
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control the natural gas heating value is typically uneconomical as it
generally requires a
nitrogen source (e.g., an air separation plant) that is relatively costly to
operate. While the
dilution methods can produce "on-spec" heating values, the effects on LNG
compositions are
relatively minor, and the final composition (especially with respect to C2 and
C3+
components) may still be unacceptable for the environmental standards of the
North America
or other environmental sensitive markets. Consequently, a LNG stripping
process or other gas
fractionation step must be employed, which generally necessitates vaporizing
the.LNG in a
flash drum and stripping in a demethanizer operating at low pressures, with
the flash vapor
and/or demethanizer overhead compressed to a higher pressure and re-condensed
to a liquid
1o form using inlet LNG as a coolant and then pumped and vaporized in the
vaporizers. These
processes are energy inefficient when high propane and ethane recoveries are
required on
processing richer LNG (LNG with high ethane and propane and heavier content)
for
regulation compliance, because these processes would require operating the
flash drum and
demetlianizer at an even lower pressure that would significantly increase the
compression
costs. An exemplary regasification process and configuration is described in
U.S. Pat. No.
6,564,579 to McCartney.
In addition to removal of C2+ components to meet sales gas heating values,
there are
also revenue opportunities for producing C2 and C3 for sales since the value
of these NGL
components is generally higher than that of natural gas, especially when
ethane can be used as
petrochemical feedstock, and the propane and heavier components can be sold as
transportation fuel. Unfortunately, the consumer markets of these liquid
products are typically
at a significant distance from the LNG regasification terminals, and dedicated
pipeline
transportation systems would have to be installed. Additionally, the C2 or C3
market is often
subject to seasonal fluctuation. Therefore, there is a need to provide
flexibility that allows a
facility to operate on either ethane recovery or ethane rejection (propane
recovery only), or
that allows varying ethane recovery level. Unfortunately, most current NGL
plants fail to
address these operating modes, subsequently losing the potential revenue
benefits from the
operation from ethane recovery to ethane rejection or vise versa.
Consequently, while numerous processes and configurations for LNG
regasification
3o are known in the art, all of almost all of them suffer from one or more
disadvantage. Most
notably, many of the currently known processes are energy inefficient, and
inflexible in
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meeting the heating values and composition requirements. Thus, there is still
a need to
provide improved configurations and methods for gas processing in LNG
regasification.
Summary of the Invention
The present invention is directed to configurations and methods of processing
LNG in
which the pressure of one portion of the LNG is set to a processing pressure
at which LNG
processing takes place to thereby generate a processed (typically lean) LNG.
The so formed
processed LNG may then be further pressurized to a delivery pressure and
combined with a
second portion of (typically unprocessed) LNG at delivery pressure to so
generate LNG with a
desired and predetermined chemical composition and heating value. Preferably,
processing of
the LNG is performed in a refluxed demethanizer that allows removal and/or
recovery of at
least 99% propane and over 70% ethane from the LNG.
In one aspect of the inventive subject matter, a LNG processing plant includes
a LNG
source that provides a first portion of LNG and a second portion of LNG. A
processing unit is
fluidly coupled to the LNG source and receives the first portion, wherein the
unit removes
heavier components in the first portion to thereby produce a lean LNG. A
combination unit
then combines the lean LNG and the second portion of the LNG to a form a
processed LNG.
Preferably, contemplated LNG processing plants comprise a pump that pumps at
least
one of the first and second portions to a feed pressure, and further include a
demethanizer that
receives at least part of the second portion at a pressure lower than the feed
pressure. Most
preferably, the demethanizer produces an overhead product, wherein a heat
exchanger cools
at least part of the demethanizer overhead vapor to thereby produce a reflux
stream for the
demethanizer, and/or wherein a heat exchanger condenses at least part of the
overhead vapor
from the demethanizer reflux drum to thereby produce the lean LNG.
In still further preferred aspects, contemplated LNG processing plants are
configured
to combine the first portion and the lean LNG to thereby form the processed
LNG, and the
processed LNG is then pumped and vaporized at pipeline pressure in a manner
well known in
the art. Moreover, contemplated plants may also include a control circuit that
is configured to
control a mass flow ratio between the first and second portion. Using such
control circuits, it
should be appreciated that the heating value of the combined processed and
unprocessed LNG
can be maintained at a predetermined level while the LNG entering the plant
may have
variable chemical compositions and/or heating values. Where desired, the plant
may further
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include a turbo-generator that is driven by expansion of a heated and
pressurized portion of
the first portion of LNG to thereby produce energy.
In another aspect of the inventive subject matter, the LNG processing plant
has a heat
exchanger that is configured such that at least part of a refrigeration
content of LNG passing
through the exchanger provides refrigeration to a demethanizer reflux stream
and fiuther
provides condensation cold for a demethanizer reflux drum overhead product,
and wherein
the reflux stream and the demethanizer reflux drum overhead product are
produced from the
LNG passing through the exchanger. Particularly preferred plants also include
a demethanizer
that is coupled to the exchanger such that at lea'st part of the LNG passing
through the
exchanger is fed to the demethanizer to thereby form at least one of the
demethanizer reflux
stream and a condensed demethanizer reflux drum overhead product. Most
typically, the LNG
passing through the exchanger has a pressure of between 300 psig to 600 psig.
A pump may
be coupled to the exchanger that pumps the condensed demethanizer reflux drum
overhead
product to a delivery pressure, and a combination unit may be included in
which the
condensed demethanizer reflux drum overhead product at delivery pressure is
combined with
LNG.
Consequently, the inventors contemplate a method of processing LNG in whicli
in one
step LNG is provided and pumped to a feed pressure. hi a further step, the LNG
is divided at
feed pressure in a first and second portion. In yet another step, pressure is
reduced in the first
portion to a separation pressure and heavier components are separated from the
first portion at
the separation pressure to thereby form a lean LNG. In still another step, the
lean LNG is
pumped to a delivery pressure, and the lean LNG and the second portion of the
LNG are
combined to form a processed LNG.
Preferred feed pressures are between about 700 psig and 1300 psig, while
separation
pressures are preferably between about 300 psig and 650 psig, and delivery
pressures are
preferably between about 700 psig and 1300 psig. Separation of the heavier
components from
the first portion is typically performed in a demethanizer that produces a
demethanizer
overhead product, wherein most preferably at least one portion of the
demethanizer overhead
product is condensed to thereby form the lean LNG, and optionally another
portion of the
demethanizer overhead product is cooled to form a reflux stream for the
demethanizer.
In especially contemplated plants where ethane recovery or ethane rejection or
varying
levels of ethane recovery is desirable, the demethanizer bottoms can be
further processed in a
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deethanizer column to produce a C2 overhead liquid, and a
C3+ bottoms product. In this case, the deethanizer overhead
reflux duty can be supplied by the refrigeration content of
the inlet LNG. Ethane rejection or varying level of ethane
recovery can be efficiently achieved by diverting at least a
portion of the liquid ethane product from the deethanizer
overhead to blend with the lean LNG. Such configuration
allows the flexibility of switching between ethane recovery
to ethane rejection mode or vise versa, without altering the
upstream processing conditions.
According to one aspect of the present invention,
there is provided a LNG processing plant comprising: a LNG
source that provides a first portion of LNG and a second
portion of LNG; a processing unit that is fluidly coupled to
the LNG source and that receives the first portion, wherein
the unit is configured to remove heavier components in the
first portion to thereby produce a lean LNG; and a
combination unit in which the lean LNG and the second
portion of the LNG are combined to a form a processed LNG.
According to another aspect of the present
invention, there is provided a method of processing LNG,
comprising: providing LNG and pumping the LNG to a feed
pressure; dividing the LNG at feed pressure in a first and
second portion; providing the first portion to a separation
pressure and separating heavier components from the first
portion at the separation pressure to thereby form a lean
LNG; pumping the lean LNG to a delivery pressure; and
combining the lean LNG and the second portion of the LNG to
form a processed LNG.
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Various objects, features, aspects and advantages of the present invention
will become
more apparent from the following detailed description of preferred embodiments
of the
lo invention, along with the accompanying drawing.
Brief Description of The Drawing
Figure 1 is a schematic view of a first exemplary plant according to the
inventive
subject matter with removal or recovery of 99% of propane in the inlet LNG.
Figure 2 is a scheniatic view of a second exemplary plant according to the
inventive
15 subject matter with removal or recovery of over 70% of ethane and 99% of
propane in the
inlet LNG.
Figure 3 is a schematic view of a third exemplary plant according to the
inventive
subject matter with renioval or recovery of 99% of propane in the inlet LNG
using an integral
reflux condensing exchanger.
20 Figure 4 is a schematic view of a fourth exemplary plant according to the
inventive
subject matter for a plant that recovers C2 and C3 while producing energy.
Figure 5 is a schematic view of a fifth exemplary plant according to the
inventive
subject matter for a plant that recovers C3 while producing energy.
Figure 6 is a schematic view of a sixth exemplary plant according to the
inventive
25 subject matter with removal or recovery of 99% of propane and 2% to 70%
ethane recoveries
from the inlet LNG, demonstrating the switching method betxveen ethane
recovery to ethane
rejection or varying levels of ethane recovery.
Figure 7 is a schematic view of a seventh exemplary plant according to the
inventive
subject matter for propane or ethane delivery using a batching NGL pipeline.
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Figure 8 is a graph depicting heating values of LNG from various LNG export
plants
in the Atlantic, Pacific and Middle East market.
Figure 9 is a graph depicting chemical composition of LNG for the LNG of
Figure 8.
Detailed Description
The inventors discovered that LNG can be processed in a manner that takes
advantage
of the relatively large refrigeration content in the LNG. More specifically,
the inventors have
discovered that an LNG stream can be pumped to a desired pressure and then
used to supply
reflux cooling in a demethanizer and condensing duty of the demethanizer
reflux drum vapor
to thereby produce a lean LNG that can then be combined with unprocessed LNG.
Optionally, the refrigeration content of the LNG may also supply reflux
cooling in a
deethanizer. Most preferably, the pumped LNG stream is processed in a
demethanizer (and
optionally deethanizer) to thereby form the streams that are cooled by the
pumped LNG. Such
configurations advantageously allow removal or recovery of at least 99%
propane and over
70% ethane from the LNG. Where ethane rejection or varying levels of ethane
recovery is
desirable, the demethanizer bottoms can be further processed in a deethanizer
column to
produce a C2 overhead liquid, and a C3+ bottoms product wherein ethane
rejection or varying
ethane recovery can be efficiently achieved by diverting at least a portion of
the liquid ethane
product from the deethanizer overhead to blend with the lean LNG.
In one preferred aspect of the inventive subject matter as depicted in Figure
1, LNG is
pumped and split into two portions (streams 2 and 3) as needed for heating
value control. The
first portion is heat exchanged witli the demethanizer overhead producing a
cold reflux and
condensed demethanizer overhead product (lean LNG), while the second portion
(rich LNG)
bypasses the heating value control portion. The rich LNG and lean LNG streams
can then be
combined to produce a LNG product with desired chemical composition and
heating value.
More specifically, and with further reference to Figure 1, The LNG flow rate
to the
plant is equivalent to 500 MMscfd of natural gas with a typical gas
composition shown in
Table 1 below. LNG stream 1 from storage or vapor re-condenser (or other
suitable source) is
at a pressure of about 15 to 80 psia and a temperature of typically about -260
F to -240 F.
Stream 1 is pumped by LNG pump 51 to a suitable pressure, typically about 700
psig to about
1300 psig, and most typically about 1000 psig to form a pressurized LNG
stream, which is
split into stream 2 and stream 3 as needed for heating value control. A higher
flow of stream
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3 will pass more LNG feed to the heating value control unit, thus lowering the
heating value
of the pipeline gas 16. Where high propane recoveries are desirable (e.g., due
to the market
demands), most of LNG stream 1 will be processed in the heating value control
unit. Thus, it
should be recognized that by varying the flow ratio between streams 2 and 3,
the quantity of
C2+ components in the pipeline gas can be controlled to meet specific market
requirements.
Stream 3 is letdown in pressure in valve 53 to form stream 4 at about 450 to
500 psig
that is heated and partially vaporized in exchanger 54 by heat exchange with
the demethanizer
overhead stream 8 and reflux separator vapor stream 10. The exchanger outlet
stream 5 is at
about -120 F to -140 F and is further heated in preheater 55 using a heat
transfer medium
(e.g., glycol (stream 91)) forming stream 6 at about -120 F to -115 F. The two-
phase stream 6
is then fed to the upper section of demethanizer 56. The demethanizer produces
a lean natural
overhead vapor. 8, which is reduced in (or even depleted of) propane and
heavier components
and at least partially depleted of ethane.
Demethanizer 56 preferably operates at 450 psig to 500 psig. It should be
especially
noted that side reboiler 57 can be used to assist the stripping of the light
components in
stream 17 withdrawn from the lower section of the demethanizer, with heat
supplied from
glycol stream 92. The demethanizer bottom composition is controlled by
temperature of
stream 7, at about 100 F (ethane recovery) to 200 F (propane recovery only),
using bottom
reboiler 58. Thus, it should be especially appreciated that in most aspects of
contemplated
configurations the set point of the demethanizer bottom temperature will
control the levels of
recovery and provide heating value control of the inlet LNG. Bottom product 7
can then be let
down in pressure using valve 63 and sent out as LPG stream 20.
The demethanizer overhead 8, which is typically at a pressure of about 450
psig to
500 psig and a temperature of at about -90 F to -120 F is cooled and partially
condensed in
exchanger 54 at a temperature of about -110 F to -140 F. The so generated two-
phase stream
9 is then separated in separator 59 into a liquid stream 11 and a lean vapor
stream 10. Liquid
stream 11, containing residual propane and/or ethane components, is pumped by
reflux pump
60 and returned to the top of the demethanizer as a cold reflux stream 12. The
separator vapor
stream 10 is returned to exchanger 54 and further cooled and condensed forming
stream 13.
It should be especially recognized that overhead exchanger 54 provides two
functions,
providing reflux to the demethanizer that is essential to achieve a high
propane and ethane
recovery, and to condense the separator vapor to a liquid that allows the
liquid to be pumped,
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thus substantially reducing capital and operational cost. The lean liquid
stream 13, typically at
a temperature of about -130 to -140 F is pumped by pump 61 to about 1000 psig
pressure as
necessary for pipeline transportation or combination with rich LNG stream 2.
The pressurized
lean LNG stream 14 is mixed with stream 2 of the rich LNG and fiuther heated
in vaporizer
62 to about 50 F, or other temperature needed to meet pipeline requirements.
It should be
note that suitable heat sources for the LNG vaporizer include all known heat
sources (direct
heat sources such as fired heaters, seawater exchangers, etc., or indirect
heat sources such as
glycol heat transfer systems). Valves 52 and 53 are preferably regulated by a
control system
(not shown) that adjusts the mass flow between streams 2 and 3 to a
predetermined ratio
(most typically to achieve a desired chemical composition and/or heating
value).
Alternatively, contemplated heat integration and process configurations can
also be
used for ethane recovery as depicted in the exemplary plant configuration of
Figure 2. Here,
ethane recovery can be varied from 5% up to 80% as needed for heating value
control of the
rich LNG stream 1. With respect to the numerals of the components of Figure 2,
it should be
noted that same components of Figures 1 and 2 have same numerals in Figure 2.
In general, the front end of the configuration according to Figure 2 is
similar to that
shown in Figure 1. However, a second column 64 (the deethanizer) is added such
that the
deethanizer receives liquid stream 7 from the demethanizer 56. Stream 7 is
letdown using
valve 63 to a pressure of about 200 psig to 350 psig to form stream 19 that is
fed to the mid
section of deethanizer 64. It should be appreciated that the operating
pressure of the
deethanizer can be varied as needed to meet the pressure requirements of the
ethane product.
The deethanizer overhead stream 21 is advantageously at least partially
condensed in
exchanger 65 using the refrigeration content of lean LNG stream 14. The two-
phase stream 22
at about 0 F to 30 F is separated in separator 66 into a liquid stream 23 and
an ethane vapor
product stream 25. A portion of the liquid stream is pumped by reflux pump 67
and returned
to the deethanizer overhead as reflux stream 24. Optionally, where liquid
ethane product is
desired, a portion of the liquid can be produced as stream 26. The ethane
vapor can be used as
a fuel source in the submerged combustion LNG vaporizer, used to fuel a power
plant, and/or
for petrochemical production. The deethanizer produces a bottom product stream
20 with heat
supplied by reboiler 68 (e.g., using a glycol heat transfer system as a heat
source). Lean
cooled LNG stream 15 can then be combined with the rich LNG and vaporized in
heater 62 to
form pipeline gas 16 having desired chemical composition and/or heating value.
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Alternatively, the overhead reflux exchanger in the demethanizer can be
integrated in
the column as shown in the exemplary plant configuration of Figure 3. Here,
pumped rich
LNG is used in an overhead reflux condenser 69 integral to the column,
producing an internal
reflux stream 10 that is free flowing to the lower section of the column. The
heated LNG
stream 6 from exchanger 69 is sent to the upper section of the demethanizer,
below the reflux
exchanger 69. Again, with respect to the numerals of the components of Figure
3, it should
be noted that same components of Figures 1 and 3 have same numerals in Figure
3.
Therefore, it should be recognized that numerous advantages may be achieved
using
configurations according to the inventive subject matter. Among other things,
it should be
appreciated that contemplated configurations (by virtue of modifying the split
ratio of the
inlet LNG stream and temperature in the heating value control section) allow
processing of
LNG with varying compositions and heat contents while producing an "on spec"
natural gas
and/or LNG transportation fuel for the North American market or other emission
sensitive
markets. Moreover, contemplated configurations will produce high-purity ethane
as
commercial product or as energy source for the combined cycle power plant.
In a still further contemplated aspect, power can be generated using the LNG.
Most
preferably, a heat source heats the liquid portion of the LNG (typically after
passage of the
LNG through the exchanger), wherein the LNG may be further pumped to a higher
pressure
before heating. The so pumped and heated LNG is then expanded to produce work
in an open
cycle (typically without the typical re-circulation of the LNG in known
configurations) prior
to entry into the demethanizer. In especially preferred plants, the LNG
processing plant has a
deinethanizer and a deethanizer, wherein the demethanizer removes C2+
components from the
LNG using the expanded vapor from the expander as a stripping medium, and
wherein the
reflux duties of the demethanizer and deethanizer overhead condenser are
provided by the
refrigeration content in the LNG in a manner substantially similar as
described above in
Figures 1-3. Preferably, the open LNG expansion cycle supplies at least a
portion of the
power demand for the LNG regasification plant. However, in alternative
aspects, so
generated power can also be employed in other portions of the plant, or be
sold at a premium.
Therefore, it should be appreciated that contemplated plants may comprise a
pump
and a heat source that heats a first portion of a liquefied natural gas, and
an expander in which
the pumped and heated liquefied natural gas is expanded to produce work. It is
still further
preferred that at least a portion of the expanded gas is fed into a
demethanizer as a stripping
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gas to produce a lean gas (at least partially depleted from ethane) and a
demethanized bottom
product, wherein the lean gas may be re-condensed using at least part of the
refrigeration
content of the LNG. The demethanizer bottom product may then be fed to a
deethanizer that
produces an ethane product and a liquefied petroleum gas product.
Additionally, or alternatively, at least a portion of the reflux condenser
duty of the
demethanizer and deethanizer is provided by the refrigeration content of a
portion of the
liquefied natural gas before the heat source heats the liquid portion of the
liquefied natural
gas, and/or that a second portion of the liquefied natural gas (vapor portion)
is separated in a
demethanizer into a lean gas and a demethanized bottom product.
With respect to the power producing configurations of Figures 4 and 5, it
should be
noted that the same considerations apply for corresponding components and
operating
conditions as described above for plants according to Figures 1-3. Here,
Figure 4 exemplarily
depicts a configuration in which power is generated and in which C2 and C3
components are
recovered, whereas Figure 5 exemplarily depicts a configuration in which power
is generated
and in which C3 components are recovered.
In these configurations, after the LNG is pumped wit11 pump 51 and heated in
exchanger 54 to a two-phase stream, the LNG is separated in a separator 151.
The separator
vapor stream 101 is fed to the upper section of the demethanizer 56, and the
separator liquid
stream 102 is pumped by LNG booster pump 152 to about 2500 psig to 3500 psig
forming
stream 103. The pressurized liquid is heated by an external heat source in
exchanger 153
using a heat medium 99 forming stream 104 at about 400 F to 500 F. Various
heat sources
can be applied, including waste heat sources from flue gas, process waste
heat, and ambient
heat and/ or fuel fired combustion heater, and the choice depends on
availability and
economics. Stream 104 is then expanded in an expander 154 to stream 105 at a
pressure of
about 400 psig to 500 psig, generating about 15,000 HP that can be used to
supply the power
requirement in the regasification process including pump 152 with the excess
power being
exported for sales.
The expander outlet stream 105 at about 200 F to 300 F is fed into
demethanizer 56
operating at 400 psig to 500 psig. It should be especially noted that stream
105 supplies at
least a portion, if not all of the reboiler heat required by the demethanizer.
The reflux duty for
demethanizer 56 is provided by inlet LNG stream 4, in exchanger 54. It should
be especially
noted that such reflux/stripping configurations are self-contained and
typically do not require
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any additional heat consumption. If required, a side reboiler 57 or bottom
reboiler 58 can be
used to supplement the heating requirement. Demethanizer overhead 8 is re-
condensed in
exchanger 54, separated in separator 59 with the liquid pumped by pump 60 to
form stream
12, and with the lean LNG 14 (via 10 and 13) being further heated in exchanger
65 and 62. It
should be recognized that higher expander inlet pressure may be used to
increase power
output and efficiency. However, there is an economic trade-off between higher
power
revenues and the higher equipment costs. In most cases, higher
expander=pressure is only
desirable where electric power can be sold at a premium.
In additionally contemplated aspects of the inventive subject matter, it
should also be
recognized that an LNG plant can also be operated in an ethane recovery or
ethane rejection
(propane recovery) mode as depicted in the exemplary plant configuration of
Figure 6. Here,
ethane recovery can be varied from about 2% to about 80% as needed to meet the
ethane
market demand. The term "about" where used herein in conjunction with a
numeral refers to a
+/- 10% range of that numeral. The configuration of such process is similar to
that of Figure 2
with some variations. Thus, and with respect to the configurations of Figures
6 and 7, it
should be noted that the same considerations apply for corresponding
components and
operating conditions as described above for plants according to Figure 2.
In plants according to Figure 6, the rich LNG heating system is configured in
one or
more heating and separation steps prior to the demethanizer 56. LNG stream 5
from
exchanger 54 is heated using the deethanizer reflux condenser duty in
exchanger 65, and is
further heated in exchanger 55 using an external heat source 91 forming stream
6. The two
phase stream 6 is then separated in separator 87 producing flashed vapor
stream 73 that is
routed to the upper section of the demethanizer 56 (via valve 86), and liquid
stream 71 that is
fed to the mid section of the demethanizer as stream 72 after the liquid
stream is heated by an
external heat source 99 in exchanger 88. Generally, the operation and
conditions of for the
demethanizer and deethanizer are similar to those in the plant of Figure 2
with the exception
that the deethanizer overhead C2 liquid stream 26 is-pumped by pump 89 to
about 1300 psig
or the sales pipeline pressure. The amount of ethane production can be varied
by diverting at
least a portion of the excess ethane liquid stream 75 via valve 90 to blend
with the lean LNG
stream 14 (and/or rich LNG stream 2, and/or mixture of streams 2 and 14)
forming stream 77,
prior to being heated in the conventional LNG vaporizer 62. Alternatively,
this ethane
blending method can be used to produce natural gas when a higher heating value
is desirable
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CA 02574601 2007-01-19
WO 2006/004723 PCT/US2005/022880
for the sales gas pipeline sales by increasing the ethane flow stream 75.
Thereby, by varying
the C2 flow using the diverting valve 90, the heating value of natural gas can
be controlled
and the amount of ethane production can be varied to meet facility
requirements, regardless of
the import LNG heating values.
Similarly, contemplated NGL recovery plants can also be operated to produce
propane
and ethane liquid product that can be pumped and transported to distant
locations via a
batching pipeline as shown in the exemplary plant configuration of Figure 7,
similar to that
of Figure 6 with some variations. Thus, and with respect to the configurations
of Figure 7, it
sllould be noted that the same considerations apply for corresponding
components and
1o operating conditions as described above for plants according to Figure 6.
Here, a single pipeline is used to transport either C2 or C3+, in an
alternating mode to
various pipeline systems or industrial sites and further includes liquid
storage, pumping, and a
batching pipeline. Most typically, one or more days of liquid product storage
capacities are
provided to ensure stable operation in C3+ product storage tank 100 and C2
product storage
tank 101. High pressure liquid product pumps 89 and 102 are respectively used
to pump the
C2 or C3+ product to NGL pipeline 104 operating at typically 1300 psig or
higher pressure.
Using a single pipeline in delivering the C2 and C3+ product in a batching
mode eliminates
the need for two dedicated C2 and C3+ pipeline, significantly reducing
pipeline associated
costs.
Therefore, it should be appreciated that numerous advantages may be achieved
using
configurations according to the inventive subject matter. For example,
contemplated
configurations provide a highly efficient LNG power generation cycle that can
be coupled
with a heating control unit utilizing fractionation, and re-condensation.
Viewed from another
perspective, it should be appreciated that configurations contemplated herein
allow LNG
regasification plants to be less dependent on an external power supply, thus
making such
configurations even more economical and flexible while at the same time
providing the
capability of processing of LNG with varying compositions and heat contents to
meet pipeline
specifications.
Preferred configurations are suitable as an add-in unit for a new installation
or as a
3o retrofit installation for heating value control of the inlet LNG, producing
a lean LNG, LPG
and ethane. By controlling the portion of LNG feed and the levels of propane
and ethane
removal, the desirable heating value or liquid product flow can be maintained.
Any type of
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CA 02574601 2007-01-19
WO 2006/004723 PCT/US2005/022880
heat sources for regasification are deemed suitable, however, particularly
preferred heat
sources include waste heat from power plant.
Thus, it should be recognized that in some of preferred plants, a demethanizer
and
deethanizer operate in a manner in which the demethanizer removes C2+
components from
the LNG using reboiler and/ or side reboiler heat, and wherein at least a
portion of reflux
condensing duty of the demethanizer is provided by the refrigeration content
of the rich LNG.
Furthermore, the cold for the deethanizer overhead condenser may be provided
by the
refrigeration from the lean LNG after the lean LNG is pumped to pipeline
pressure.
Therefore, in one aspect of the inventive subject matter, at least a portion
of the demethanizer
overhead is cooled, partially condensed and separated, and the separated
liquid is returned to
the demethanizer as reflux with the separator lean gas (partially or entirely
depleted in
ethane), further cooled and condensed by inlet LNG forming a liquid phase. The
liquid phase
is then further pumped to pipeline pressure, supplying the refrigeration
requirement of the
deethanizer, and then heated in conventional vaporizers. The demethanizer
bottom product
may be fed to a deethanizer that produces ethane vapor and/or ethane liquid
product and a
liquefied petroleum gas product, wherein at least in some configurations the
ethane product is
employed as a fuel in the vaporizers or used as fuel gas in a power plan.t or
be sold as a
chemical feedstock. In further preferred aspects of contemplated plants, at
least a portion of
the reflux condenser duty of the deethanizer may be provided by the
refrigeration content of a
portion of the liquefied natural gas after the demethanizer reflux separator
vapor is condensed
and pumped to pipeline pressure.
Alternatively, or additionally, contemplated plants may include a deethanizer,
wherein the inlet LNG (rich gas) or the outlet LNG (lean gas) provides reflux
condenser duty
for the deethanizer before the LNG is heated for pipeline specification. In at
least some of
such plants, the demethanizer may produce a bottom product that is fed to the
deethanizer,
wherein the deethanizer produces a liquefied petroleum gas (C3+) product and
an ethane
product, which may then be sold for petrochemical feedstock or combusted as a
turbine fuel
in a combined cycle power plant. Where appropriate (e.g., to reduce safety
concerns), heating
of the first portion is provided by a heat transfer fluid (e.g., a glycol
water mixture) that
transfers heat from heat sources, such as fuel fired heater, ambient air,
water circulating
system, the gas turbine combustion air, the steam turbine discharge, the heat
recovery unit,
and/or the flue gas stream. Viewed from a different perspective, contemplated
plants will
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CA 02574601 2007-01-19
WO 2006/004723 PCT/US2005/022880
receive a liquid natural gas feed that is split in a first portion and a
second portion, wherein
the first portion enters the heating value control section, and wherein the
second portion is fed
to the vaporizer (most preferably after combination with the lean LNG).
In further especially contemplated plants, ethane recovery, ethane rejection,
or varying
levels of ethane production are met by diverting at least a portion of the
liquid ethane product
from the deethanizer overhead to blend with the lean LNG prior to being heated
in the
conventional vaporizers. Such configuration allows flexibility of switching
between ethane
recovery to ethane rejection mode, or vice versa, that maybe necessary to meet
the sales gas
heating value specification or to accommodate the changes in the ethane market
demand,
while maintaining substantially the same process conditions in the
demethanizer and
deethanizer for all operations. Contemplated NGL recovery plant can also be
operated to
produce propane and ethane products that can be transported to distant
pipeline systems or
industrial sites via a single batching pipeline operating on alternating
modes. The use of the
batching pipeline has eliminated the need for two dedicated pipelines for C2
and C3+
products, significantly reducing the pipeline cost.
Examples
Exemplafy Calculation of Components in Selected Streanzs
In an exemplary configuration substantially identical with the plant
configuration as
shown in Figure 1, the mol fraction of various components of selected streams
were
calculated, and the results are listed in Table 1 below. LPG is the C3+ bottom
fraction of the
demethanizer stream 20, and the pipeline gas is depicted as stream 16 .
Table 1
Component LNG Feed Ethane LPG Pipeline Gas
N2 0.0065 0.0000 0.0000 0.0073
C1 0.8816 0.0176 0.0000 0.9878
C2 0.0522 0.9723 0.0053 0.0042
C3 0.0328 0.0092 0.5407 0.0006
iC4 0.0071 0.0000 0.1206 0.0000
NC4 0.0107 0.0000 0.1818 0.0000
iC5 0.0040 0.0000 0.0673 0.0000
NC5 0.0020 0.0000 0.0337 0.0000
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C6 + 0.0030 0.0000 0.0505 0.0000
Heat Value Btu/SCF (HHV) 1,153 1,750 2,985 999
MMscfd 500 25 30 450
Barrel per day 218,000 16,000 21,000 181,000
Thus, specific embodiments and applications of LNG regasification
configurations
and methods have been disclosed. It should be apparent, however, to those
skilled in the art
that many more modifications besides those already described are possible
without departing
from the inventive concepts herein. The inventive subject matter, therefore,
is not to be
restricted except in the spirit of the appended claims. Moreover, in
interpreting both the
specification and the claims, all terms should be interpreted in the broadest
possible manner
consistent with the context. In particular, the terms "comprises" and
"comprising" should be
interpreted as referring to elements, components, or steps in a non-exclusive
manner,
indicating that the referenced elements, components, or steps may be present,
or utilized, or
combined with other elements, components, or steps that are not expressly
referenced.
Furthermore, where a definition or use of a term in a reference, which is
incorporated by
reference herein is inconsistent or contrary to the definition of that term
provided herein, the
definition of that term provided herein applies and the definition of that
term in the reference
does not apply.
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