U.S. patent application number 12/353956 was filed with the patent office on 2010-07-15 for methods and apparatus for liquefaction of natural gas and products therefrom.
Invention is credited to SUSAN T. WALTHER.
Application Number | 20100175425 12/353956 |
Document ID | / |
Family ID | 42318046 |
Filed Date | 2010-07-15 |
United States Patent
Application |
20100175425 |
Kind Code |
A1 |
WALTHER; SUSAN T. |
July 15, 2010 |
METHODS AND APPARATUS FOR LIQUEFACTION OF NATURAL GAS AND PRODUCTS
THEREFROM
Abstract
A method for cooling natural gas with a refrigerant, one
non-limiting embodiment which includes: (A) compressing and cooling
the refrigerant to a first pressure to form a compressed
refrigerant; (B) splitting the compressed refrigerant into a first
stream and a second stream both at the first pressure; (C) cooling
the first stream to form a cooled first stream; (D) expanding the
cooled first stream to a first expansion pressure to form an
expanded first stream; (E) compressing the second stream to a
second pressure higher than the first pressure, forming a higher
pressure second stream; (F) cooling the higher pressure second
stream to form a cooled second stream; (G) expanding the cooled
second stream to a second expansion pressure to form an expanded
second stream; and, (H) Cooling the natural gas with the expanded
first stream and expanded second stream, forming a cooled natural
gas stream.
Inventors: |
WALTHER; SUSAN T.;
(Sugarland, TX) |
Correspondence
Address: |
GILBRETH & ASSOCIATES, P.C.
PO BOX 2428
BELLAIRE
TX
77402-2428
US
|
Family ID: |
42318046 |
Appl. No.: |
12/353956 |
Filed: |
January 14, 2009 |
Current U.S.
Class: |
62/623 ; 62/618;
62/620 |
Current CPC
Class: |
F25J 2220/64 20130101;
F25J 2220/62 20130101; F28F 9/0275 20130101; F25J 1/0262 20130101;
F25J 1/0212 20130101; F25J 1/004 20130101; F25J 1/005 20130101;
F25J 2235/60 20130101; F25J 1/0077 20130101; F25J 1/0204 20130101;
F28D 9/00 20130101; F25J 1/0072 20130101; F25J 2230/08 20130101;
F25J 2270/16 20130101; F25J 1/007 20130101; F25J 1/0272 20130101;
F25J 1/0278 20130101; F25J 5/002 20130101; F25J 2230/32 20130101;
F28F 9/26 20130101; F25J 1/0075 20130101; F25J 1/0022 20130101;
F25J 1/0288 20130101; F25J 2220/68 20130101; F28D 9/0093 20130101;
F25J 2210/06 20130101 |
Class at
Publication: |
62/623 ; 62/618;
62/620 |
International
Class: |
F25J 3/00 20060101
F25J003/00 |
Claims
1. A method for cooling natural gas with a refrigerant, the method
comprises: (A) Compressing and cooling the refrigerant to a first
pressure to form a compressed refrigerant; (B) Splitting the
compressed refrigerant into a first stream and a second stream both
at the first pressure; (C) Cooling the first stream to form a
cooled first stream; (D) Expanding the cooled first stream to a
first expansion pressure to form an expanded first stream; (E)
Compressing the second stream to a second pressure higher than the
first pressure, forming a higher pressure second stream; (F)
Cooling the higher pressure second stream to form a cooled second
stream; (G) Expanding the cooled second stream to a second
expansion pressure to form an expanded second stream; and, (H)
Cooling the natural gas with the expanded first stream and expanded
second stream, forming a cooled natural gas stream.
2. The method of claim 1, wherein prior to step (H) the natural gas
is first pretreated to remove at least one selected from the group
consisting of non-hydrocarbon impurities, nitrogen, carbon dioxide,
hydrogen sulfide, carbonyl sulfide, mercaptans water, and
helium.
3. The method of claim 1, wherein prior to step (H) the natural gas
is first pretreated to reduce the quantity of C6+ hydrocarbon
components.
4. The method of claim 1, wherein in step (B) the refrigerant is
split into a third or more streams.
5. The method of claim 1, wherein at least one of the first
expansion pressure or the second expansion pressure is less than
1.18 MPa.
6. The method of claim 1, wherein the natural gas is split into
multiple portions, each portion cooled in parallel with the other
portions.
7. The method of claim 1, wherein a portion of the cooled natural
gas stream is used to pretreat the natural gas.
8. The method of claim 1, wherein in step (H) there is formed a
heated first stream, a heated second stream, the method further
comprising combining, compressing and cooling the heated first
stream and the heated second stream to form the refrigerant for use
in step (A).
9. A method for cooling natural gas with a refrigerant, the method
comprises: (A) Compressing and cooling the refrigerant to a first
pressure to form a compressed refrigerant; (B) Splitting the
refrigerant into a first stream and a second stream both at the
first pressure; (C) Cooling the first stream to form a cooled first
stream; (D) Expanding the cooled first stream to a first expansion
pressure to form an expanded first stream; (E) Compressing second
stream to a second pressure higher than the first pressure forming
a higher pressure second stream; (F) Cooling the higher pressure
second stream to form a cooled second stream; (G) Expanding the
cooled second stream to form a expanded second stream at a second
expansion pressure; and, (H) Cooling the natural gas with the
expanded first stream and the expanded second stream to form a
cooled natural gas stream, wherein the natural gas is at a pressure
of at least 5.5 MPa; wherein at least step (H) is carried out in at
least one aluminum plate heat exchanger.
10. The method of claim 9, wherein in step (H) the pressure is at
least 6 MPa.
11. The method of claim 9, wherein prior to step (H) the natural
gas is first pretreated to remove at least one selected from the
group consisting of non-hydrocarbon impurities, nitrogen, carbon
dioxide, hydrogen sulfide, carbonyl sulfide, mercaptans water, and
helium.
12. The method of claim 9, wherein prior to step (H) the natural
gas is first pretreated to reduce the quantity of C6+ hydrocarbon
components.
13. The method of claim 9, wherein in step (B), the refrigerant is
split into at least the first stream, the second stream and a third
stream.
14. The method of claim 9, wherein at least one of the first
expansion pressure or the second expansion pressure is less than
1.15 MPa.
15. The method of claim 9, wherein the aluminum plate heat
exchanger comprises multiple cores operating in parallel and the
natural gas is split into multiple portions, each portion cooled in
one of the cores.
16. The method of claim 9, wherein a portion of the cooled natural
gas stream is used to pretreat the natural gas.
17. The method of claim 9, wherein in step (H) there is formed a
heated first stream, a heated second stream, the method further
comprising combining, compressing and cooling the heated first
stream and the heated second stream to form the refrigerant for use
in step (A).
18. A method for cooling natural gas with a refrigerant, the method
comprises: (A) Compressing and cooling the refrigerant to a first
pressure to form a compressed refrigerant; (B) Splitting the
refrigerant into a first stream and a second stream both at the
first pressure; (C) Cooling the first stream to form a cooled first
stream; (D) Expanding the cooled first stream to form an expanded
first stream at a first expansion pressure; (F) Compressing second
stream to a second pressure higher than the first pressure forming
a higher pressure second stream; (G) Cooling the higher pressure
second stream to form a cooled second stream; (H) Expanding the
cooled second stream to the expansion pressure to form a expanded
second stream; and, (H) Cooling the natural gas with the cooled
first stream and the cooled second stream to form a cooled natural
gas stream, wherein the natural gas is at a pressure less than 5.5
MPa; wherein, step (H) is carried out in at least one heat
exchanger selected from the group comprising a spiral wound heat
exchanger, a printed circuit heat exchanger and a spool wound heat
exchanger.
19. The method of claim 18, wherein in step (H) the pressure is
less than 5 MPa.
20. The method of claim 18, wherein in step (H) the pressure is
less than 4.5 MPa.
21. A method for cooling natural gas with a refrigerant, the method
comprises: (A) Compressing and cooling the refrigerant to a first
pressure to form a compressed refrigerant; (B) Splitting the
compressed refrigerant into a first stream and a second stream both
at the first pressure; (C) Cooling the first stream to form a
cooled first stream; (D) Expanding the cooled first stream to a
first expansion pressure to form an expanded first stream; (E)
Compressing the second stream to a second pressure higher than the
first pressure, forming a higher pressure second stream; (F)
Cooling the higher pressure second stream to form a cooled second
stream; (G) Expanding the cooled second stream to a second
expansion pressure to form an expanded second stream; and, (H)
Cooling the natural gas with the expanded first stream and the
expanded second stream forming a heated second stream; wherein at
least one of the first expansion pressure and the second expansion
pressure are less than 1.18 MPa.
22. The method of claim 9, wherein at least one of the first
expansion pressure or the second expansion pressure is less than
1.17 MPa.
23. The method of claim 9, wherein at least one of the first
expansion pressure or the second expansion pressure is less than
1.16 MPa.
24. A method for processing natural gas comprising: (A) Providing a
first natural gas vapor stream to a fractionation tower; (B)
Providing a second natural gas stream to the fractionation tower as
a reflux stream; and, (C) Separating the first natural gas vapor
stream into a heavy component liquid stream and a light component
vapor stream.
Description
RELATED APPLICATION DATA.
[0001] This application claims priority of U.S. Provisional Patent
Application No. 61/020,699, filed Jan. 14, 2008, and herein
incorporated by reference.
BACKGROUND OF THE INVENTION
[0002] 1. Field of the Invention
[0003] The present invention relates to methods and apparatus for
processing fluids and products therefrom. In another aspect, the
present invention relates to liquefaction of gases and products
therefrom. In even another aspect, the present invention relates to
methods and apparatus for liquefaction of hydrocarbons and products
therefrom. In still another aspect, the present invention relates
to methods and apparatus for liquefaction of natural gas and
products therefrom.
[0004] 2. Brief Description of the Related Art
[0005] Natural gas may come from a wide variety of sources. For
example, the production of oil is many times accompanied by the
production of natural gas. Historically, it is not unusual to flare
this associated natural gas. More recently, regulatory, economic,
and/or public relations considerations have generally dictated that
this associated natural gas be disposed of in an acceptable manner,
or recovered for sale or other use, such as, for example, as a fuel
in the production process, or re-injected back into the formation
to assist production. Other significant non-limiting examples of
natural gas sources include stranded onshore or offshore gas fields
or pipeline gas.
[0006] Where nearby processing infrastructure is available,
recovery or proper disposal of associated gas is generally not an
issue. However, in some locations, especially offshore locations,
nearby processing infrastructure does not exist, and the regulatory
and/or economic penalties related to associated gas processing,
disposal or reinjection may make the oil recovery project
economically unfeasible.
[0007] The liquefaction of natural gas to form liquefied natural
gas (LNG) is generally accomplished by reducing the temperature of
natural gas to a liquefaction temperature of about -250 F to about
-260 F at or near atmospheric pressure. This liquefaction
temperature range is typical for many natural gas streams because
the boiling point of methane at atmospheric pressure is about -259
F. In order to produce, store and transport LNG, conventional
processes known in the art require substantial refrigeration to
liquefy and maintain natural gas at its liquefaction temperature.
The most common of these refrigeration processes include: (1) the
cascade process; (2) the single mixed refrigerant process; and (3)
the propane pre-cooled mixed refrigerant process.
[0008] A cascade process produces LNG by employing several
closed-loop cooling loops, each utilizing a single pure refrigerant
and collectively configured in order of progressively lower
temperatures. The first cooling circuit commonly utilizes propane
or propylene as the refrigerant, the second circuit may utilize
ethane or ethylene, while the third circuit generally utilizes
methane as the refrigerant.
[0009] A single mixed refrigerant process produces LNG by employing
a single closed-loop cooling circuit utilizing a multicomponent
refrigerant consisting of components such as nitrogen, methane,
ethane, propane, butanes and pentanes. The mixed refrigerant
undergoes the steps of condensation, expansion and recompression to
reduce the temperature of natural gas by employing a unitary
collection of heat exchangers known as a "cold box."
[0010] A propane pre-cooled mixed refrigerant process produces LNG
by employing an initial series of propane-cooled heat exchangers in
addition to a single closed-loop cooling circuit, which utilizes a
multi-component refrigerant consisting of components such as
nitrogen, methane, ethane and propane. Natural gas initially passes
through one or more propane-cooled heat exchangers, proceeds to a
main exchanger cooled by the multi-component refrigerant, and is
thereafter expanded to produce LNG.
[0011] The following patents are merely a few of the many that
address the processing of natural gas into liquefied natural
gas.
[0012] U.S. Pat. No. 3,360,944 to Knapp et al. produces LNG by
separating a natural gas feed stream into a major stream and a
minor stream, cooling the major and minor streams to produce a
liquid component, and thereafter using a substantial portion of the
liquid component as a refrigerant for the process. The liquid
component is vaporized while undergoing heat exchange, compressed
and discharged from the process. The Knapp process results in only
a minor portion of the natural gas feed stream processed into
LNG.
[0013] U.S. Pat. No. 3,616,652 to Engal discloses a process for
producing LNG in a single stage by compressing a natural gas feed
stream, cooling the compressed natural gas feed stream to produce a
liquefied stream, dramatically expanding the liquefied stream to an
intermediate-pressure liquid, and then flashing and separating the
intermediate-pressure liquid in a single separation step to produce
LNG and a low-pressure flash gas. The low-pressure flash gas is
recirculated, substantially compressed and reintroduced into the
intermediate pressure liquid. While the Engal process produces LNG
without the use of external refrigerants, the process inefficiently
utilizes its limited refrigeration capacity upon the entire process
stream without conjunctive use of multiple separation steps to
offset this severe cooling requirement. Furthermore, the Engal
process inefficiently expands its process stream pressure to a
level that results in a substantial and highly inefficient
recompression of its flash gas. Consequently, the Engal process
yields a small volume of LNG compared to the amount of work
required for its production, thus reducing the cost viability of
the process.
[0014] U.S. Pat. No. 5,755,114 issued to Foglietta, discloses a
hybrid liquefaction cycle for the production of LNG. The Foglietta
process passes a pressurized natural gas feed stream into heat
exchange contact with a closed-loop propane or propylene
refrigeration cycle prior to directing the natural gas feed stream
through a turboexpander cycle to provide auxiliary refrigeration.
The Foglietta process can be implemented with only one closed-loop
refrigeration cycle, as opposed to cascade type mixed refrigerant
systems. However, the Foglietta process still requires at least one
closed-loop refrigeration cycle comprising propane or propylene,
both of which are explosive, not easily dispersed, and which must
be stored and handled.
[0015] U.S. Pat. No. 5,768,912, issued Jun. 23, 1998, to Dubar,
discloses a process for producing a liquefied natural product such
as LNG where a single phase nitrogen refrigerant is used in such a
way that the refrigerant stream is divided into at least two
separate portions which are passed through separate turbo-expanders
before being admitted to separate heat exchangers so that the
warming curve of the refrigerant more closely matches the cooling
curve of the product being liquefied so as to minimize
thermodynamic inefficiencies and hence power requirements involved
in operation of the method.
[0016] U.S. Pat. No. 5,791,160, issued Aug. 11, 1998, to Mandler et
al., discloses a control system for a process of liquefied natural
gas production (LNG) from natural gas using a heat exchanger and a
closed loop refrigeration cycle employing independent, direct
control of both production and temperature by adjusting
refrigeration to match a set production. The control system sets
and controls LNG production at a required production value, and
independently controls LNG temperature by adjusting the
refrigeration provided to the natural gas stream. One exemplary
method employs compressor speed, for example, as a key manipulated
variable (MV) to achieve fast and stable LNG temperature
regulation. Other compressor variables rather than speed may be key
MVs, depending on the type of MR compressors employed, and may be
the guidevane angle in a centrifugal compressor or the stator blade
angle in an axial compressor. The second exemplary method employs a
ratio of total recirculating refrigerant flow to LNG flow as the
key manipulated variable to effectively control the LNG
temperature.
[0017] U.S. Pat. No. 5,916,260, issued Jun. 29, 1999, to Dubar
discloses a natural gas liquefaction process comprising passing
natural gas through a series of heat exchangers in countercurrent
relationship with a gaseous refrigerant circulated through a work
expansion cycle. The work expansion cycle comprises compressing the
refrigerant, dividing and cooling the refrigerant to produce at
least first and second cooled refrigerant streams, substantially
isentropically expanding the first refrigerant stream to a coolest
refrigerant temperature, substantially isentropically expanding the
second refrigerant stream to an intermediate refrigerant
temperature warmer than said coolest refrigerant temperature, and
delivering the refrigerant in the first and second refrigerant
streams to a respective heat exchanger for cooling the natural gas
through corresponding temperature ranges. The refrigerant in the
first stream is isentropically expanded to a pressure at least 10
times greater than the total pressure drop of the first refrigerant
stream across said series of heat exchangers, said pressure being
in the range of 1.2 to 2.5 MPa. While the Dubar process is
effective, it is relatively complex, utilizing a number of heat
exchangers manifolded in series. It utilizes a separate chilled
water loop to cool both the inlet gas to the liquefaction process
and the high-pressure refrigerant gas entering the liquefaction
process. At pressures above about 5.5 MPa, the Dubar process
utilizes a spiral wound heat exchanger, a PCHE, or a spool wound
heat exchanger rather than an aluminum plate heat exchanger.
[0018] U.S. Pat. No. 6,023,942 to Thomas et al. discloses a process
for producing a methane-rich liquid product having a temperature
above about -112. degree. C. (-170.degree. F.) at a pressure that
is sufficient for the liquid product to be at or below its bubble
point. The resulting product is a pressurized liquid natural gas
("PLNG"), which has a pressure substantially above atmospheric
pressure. While the Thomas et al. process can be implemented
without external refrigeration, the product is pressurized
requiring the use of specially designed heavy, thick-walled
containers and transports (e.g., a PLNG ship, truck or railcar).
This higher pressure, heavier walled equipment adds substantial
weight and expense to any commercial project. The PLNG consumer
will also require additional liquefaction, transport, and storage
equipment to consume the PLNG, adding further cost to the supply
and demand value chain.
[0019] U.S. Pat. No. 6,250,105, issued Jun. 26, 2001, to Kimble et
al., discloses a process for liquefying natural gas to produce a
pressurized liquid product having a temperature above -112. degree.
C. using two mixed refrigerants in two closed cycles, a low-level
refrigerant to cool and liquefy the natural gas and a high-level
refrigerant to cool the low-level refrigerant. After being used to
liquefy the natural gas, the low-level refrigerant is (a) warmed by
heat exchange in countercurrent relationship with another stream of
the low-level refrigerant and by heat exchange against a first
stream of the high-level refrigerant, (b) compressed to an elevated
pressure, and (c) aftercooled against an external cooling fluid.
The low-level refrigerant is then cooled by heat exchange against a
second stream of the high-level mixed refrigerant and by exchange
against the low-level refrigerant. The high-level refrigerant is
warmed by the heat exchange with the low-level refrigerant,
compressed to an elevated pressure, and aftercooled against an
external cooling fluid.
[0020] U.S. Pat. No. 6,298,688, issued Oct. 9, 2001, to Brostow et
al., discloses a process for gas liquefaction, particularly
nitrogen liquefaction, which combines the use of a nitrogen
autorefrigeration cooling cycle with one or more closed-loop
refrigeration cycles using two or more refrigerant components. The
closed-loop refrigeration cycle or cycles provide refrigeration in
a temperature range having a lowest temperature between about -125
F. and about -250 F. A nitrogen expander cycle provides additional
refrigeration, a portion of which is provided at temperatures below
the lowest temperature of the closed-loop or recirculating
refrigeration cycle or cycles. The lowest temperature of the
nitrogen expander cycle refrigeration range is between about -220
F. and about -320 F. The combined use of the two different
refrigerant systems allows each system to operate most efficiently
in the optimum temperature range, thereby reducing the power
consumption required for liquefaction.
[0021] U.S. Pat. No. 6,389,844, issued May 21, 2002, to Voort et
al., discloses a plant for liquefying natural gas comprising one
pre-cooling heat exchanger having an inlet for natural gas and an
outlet for cooled natural gas, a pre-cooling refrigerant circuit,
one distributor having an inlet connected to the outlet for cooled
natural gas and having two outlets, two main heat exchangers, and
two main refrigerant loops each co-operating with one liquefaction
heat exchanger.
[0022] U.S. Pat. No. 6,560,989, issued May 13, 2003, to Roberts et
al., discloses a method for the recovery of hydrogen and one or
more hydrocarbons having one or more carbon atoms from a feed gas
containing hydrogen and the one or more hydrocarbons, which process
comprises cooling and partially condensing the feed gas to provide
a partially condensed feed; separating the partially condensed feed
to provide a first liquid stream enriched in the one or more
hydrocarbons and a first vapor stream enriched in hydrogen; further
cooling and partially condensing the first vapor stream to provide
an intermediate two-phase stream; and separating the intermediate
two-phase stream to yield a further-enriched hydrogen stream and a
hydrogen-depleted residual hydrocarbon stream. Some or all of the
cooling is provided by indirect heat exchange with cold gas
refrigerant generated in a closed-loop gas expander refrigeration
cycle.
[0023] U.S. Pat. No. 6,564,578, issued May 20, 2003 to
Fischer-Calderon, is directed to a process for producing LNG by
directing a feed stream comprising natural gas to a cooling stage
that (a) cools the feed stream in at least one cooling step
producing a cooled feed stream, (b) expands the cooled feed stream
in at least one expansion step by reducing the pressure of the
cooled feed stream producing a refrigerated vapor component and a
liquid component, and (c) separates at least a portion of the
refrigerated vapor component from the liquid component wherein at
least a portion of the cooling for the process is derived from at
least a portion of the refrigerated vapor component; and repeating
steps (a) through (c) one or more times until at least substantial
portion of the feed stream in the first cooling stage is processed
into LNG wherein the feed stream in step (a) comprises at least a
portion of the liquid component produced from a previous cooling
stage.
[0024] U.S. Pat. No. 6,672,104, issued Jan. 6, 2004, to Kimble et
al. discloses a process for converting a boil-off stream comprising
methane to a liquid having a preselected bubble point temperature.
The boil-off stream is pressurized, then cooled, and then expanded
to further cool and at least partially liquefy the boil-off stream.
The preselected bubble point temperature of the resulting
pressurized liquid is obtained by performing at least one of the
following steps: before, during, or after the process of liquefying
the boil-off stream, removing from the boil-off stream a
predetermined amount of one or more components, such as nitrogen,
having a vapor pressure greater than the vapor pressure of methane,
and before, during, or after the process of liquefying the boil-off
stream, adding to the boil-off stream one or more additives having
a molecular weight heavier than the molecular weight of methane and
having a vapor pressure less than the vapor pressure of
methane.
[0025] U.S. Pat. No. 7,127,914, issued Oct. 31, 2006, to Roberts et
al., discloses a method for gas liquefaction comprising cooling a
feed gas by a first refrigeration system in a first heat exchange
zone and withdrawing a substantially liquefied stream therefrom,
further cooling the substantially liquefied stream by indirect heat
exchange with one or more work-expanded refrigerant streams in a
second heat exchange zone, and withdrawing therefrom a further
cooled, substantially liquefied stream. At least one of the one or
more work-expanded refrigerant streams is provided by compressing
one or more refrigerant gases to provide a compressed refrigerant
stream, cooling all or a portion of the compressed refrigerant
stream in a third heat exchange zone to provide a cooled,
compressed refrigerant stream, and work expanding the cooled,
compressed refrigerant stream to provide one of the one or more
work-expanded refrigerant streams. The flow rate of a work-expanded
refrigerant stream in the second heat exchange zone typically is
less than the total flow rate of one or more work-expanded
refrigerant streams in the third heat exchange zone.
[0026] U.S. Pat. No. 7,204,100, issued Apr. 17, 2007, to Wilkinson
et al., discloses a process for liquefying natural gas in
conjunction with producing a liquid stream containing predominantly
hydrocarbons heavier than methane. In the process, the natural gas
stream to be liquefied is partially cooled and divided into first
and second streams. The first stream is further cooled to condense
substantially all of it, expanded to an intermediate pressure, and
then supplied to a distillation column at a first mid-column feed
position. The second stream is also expanded to intermediate
pressure and is then supplied to the column at a second lower
mid-column feed position. A distillation stream is withdrawn from
the column below the feed point of the second stream and is cooled
to condense at least a part of it, forming a reflux stream. At
least a portion of the reflux stream is directed to the
distillation column as its top feed. The bottom product from this
distillation column preferentially contains the majority of any
hydrocarbons heavier than methane that would otherwise reduce the
purity of the liquefied natural gas. The residual gas stream from
the distillation column is compressed to a higher intermediate
pressure, cooled under pressure to condense it, and then expanded
to low pressure to form the liquefied natural gas stream.
[0027] U.S. Pat. No. 7,225,636, issued Jun. 5, 2007, to Baudat,
discloses an apparatus for and process for recovering LNG from
reservoir natural gas which includes circulating a portion of the
natural gas thru a gas cooling loop that includes heat exchanges,
an expansion zone and compression zone. The process also includes
removing liquids from the gas cooling loop, distilling those
liquids to recover a distilled gas. The process also includes
compressing and expanding various portions of the distilled gas and
passing those portions thru heat exchangers shared with the gas
cooling loop to effect heating/cooling as desired. The process also
includes removing a portion of the LNG cooling loop as LNG
product.
[0028] U.S. Pat. No. 7,310,971, issued Dec. 25, 2007, to Eaton,
discloses an improved apparatus and method for providing reflux to
a refluxed heavies removal column of a LNG facility. The apparatus
comprises stacked vertical core-in-kettle heat exchangers and an
economizer disposed between the heat exchangers. The reflux stream
originates from the methane-rich refrigerant of the methane
refrigeration cycle. The liquid reflux stream generated by cooling
the methane-rich stream in the vertical heat exchangers via
indirect heat exchange with an upstream refrigerant.
[0029] U.S. Patent Publication No 20060260358, published Nov. 23,
2006, to Eaton, discloses single or double column cryogenic
gas-separation/liquefaction devices, where refrigeration to the
device is supplied by a cryocooler alone or by a combination of a
cryocooler and by a Joule-Thompson throttling process, where the
gas condensation may occur directly on the cold portion of the
cryocooler which may be located inside of the thermally insulated
space of the distillation column(s). The invention principles
include a combined column embodiment for simultaneous production of
high-purity liquid or gaseous oxygen and nitrogen. Another double
column design offers reduced temperature and pressure separation
with easy switching between oxygen and nitrogen extraction or
single component extraction. If both gaseous and liquid oxygen are
required, oxygen purity of approximately 95% can be produced with
good recovery, i.e., with nitrogen purity of approximately 91%.
[0030] All of the patents cited in this specification, are herein
incorporated by reference.
[0031] However, in spite of the above advancements, there still
exists a need in the art for apparatus and methods for processing
and liquefying natural gas.
[0032] This and other needs in the art will become apparent to
those of skill in the art upon review of this specification,
including its drawings and claims.
SUMMARY OF THE INVENTION
[0033] It is an object of the present invention to provide for
improved apparatus and methods for processing natural gas.
[0034] This and other objects of the present invention will become
apparent to those of skill in the art upon review of this
specification, including its drawings and claims.
[0035] According to one embodiment of the present invention there
is provided a method for cooling natural gas with a refrigerant.
The method may include one or more of the following, in any order.
The method may include compressing and cooling the refrigerant to a
first pressure to form a compressed refrigerant. The method may
also include splitting the compressed refrigerant into a first
stream and a second stream both at the first pressure. The method
may even also include cooling the first stream to form a cooled
first stream. The method may still also include expanding the
cooled first stream to a first expansion pressure to form an
expanded first stream. The method may yet also include compressing
the second stream to a second pressure higher than the first
pressure, forming a higher pressure second stream. The method may
even still include cooling the higher pressure second stream to
form a cooled second stream. The method may even yet include
expanding the cooled second stream to a second expansion pressure
to form an expanded second stream. The method may still even
include cooling the natural gas with the expanded first stream and
expanded second stream, forming a cooled natural gas stream.
Various sub-embodiments of this embodiment may include any one or
more of the following in any order: wherein the natural gas is
first pretreated to remove at least one selected from the group
consisting of non-hydrocarbon impurities, nitrogen, carbon dioxide,
hydrogen sulfide, carbonyl sulfide, mercaptans water, and helium;
wherein the natural gas is first pretreated to reduce the quantity
of C6+ hydrocarbon components; wherein the refrigerant is split
into a third or more streams; wherein at least one of the first
expansion pressure or the second expansion pressure is less than
1.18 MPa; wherein the natural gas is split into multiple portions,
each portion cooled in parallel with the other portions; wherein a
portion of the cooled natural gas stream is used to pretreat the
natural gas; and wherein there is formed a heated first stream, a
heated second stream, the method further comprising combining,
compressing and cooling the heated first stream and the heated
second stream to form the refrigerant for use in the start of the
method.
[0036] According to another embodiment of the present invention
there is provided a method for cooling natural gas with a
refrigerant. The method may include one or more of the following,
in any order. The method may include compressing and cooling the
refrigerant to a first pressure to form a compressed refrigerant.
The method may also include splitting the refrigerant into a first
stream and a second stream both at the first pressure. The method
may also include cooling the first stream to form a cooled first
stream. The method may also include expanding the cooled first
stream to a first expansion pressure to form an expanded first
stream. The method may also include compressing second stream to a
second pressure higher than the first pressure forming a higher
pressure second stream. The method may also include cooling the
higher pressure second stream to form a cooled second stream. The
method may also include expanding the cooled second stream to form
an expanded second stream at a second expansion pressure. The
method may also include cooling the natural gas in at least one
aluminum plate heat exchanger with the expanded first stream and
the expanded second stream to form a cooled natural gas stream,
wherein the natural gas is at a pressure of at least 5.5 MPa.
Various sub-embodiments of this embodiment may include any one or
more of the following in any order: wherein the pressure is at
least 6 MPa, wherein the natural gas is first pretreated to remove
at least one selected from the group consisting of non-hydrocarbon
impurities, nitrogen, carbon dioxide, hydrogen sulfide, carbonyl
sulfide, mercaptans water, and helium; wherein the natural gas is
first pretreated to reduce the quantity of C6+ hydrocarbon
components; wherein the refrigerant is split into at least the
first stream, the second stream and a third stream; wherein at
least one of the first expansion pressure or the second expansion
pressure is less than 1.15 MPa, wherein the aluminum plate heat
exchanger comprises multiple cores operating in parallel and the
natural gas is split into multiple portions, each portion cooled in
one of the cores; wherein a portion of the cooled natural gas
stream is used to pretreat the natural gas; wherein there is formed
a heated first stream, a heated second stream, the method further
comprising combining, compressing and cooling the heated first
stream and the heated second stream to form the refrigerant for use
at the start of the method.
[0037] According to even another embodiment of the present
invention there is provided a method for cooling natural gas with a
refrigerant. The method may include one or more of the following,
in any order. The method may include compressing and cooling the
refrigerant to a first pressure to form a compressed refrigerant.
The method may include splitting the refrigerant into a first
stream and a second stream both at the first pressure. The method
may include cooling the first stream to form a cooled first stream.
The method may include expanding the cooled first stream to form an
expanded first stream at a first expansion pressure. The method may
include compressing second stream to a second pressure higher than
the first pressure forming a higher pressure second stream. The
method may include cooling the higher pressure second stream to
form a cooled second stream. The method may include expanding the
cooled second stream to the expansion pressure to form a expanded
second stream. The method may include cooling the natural gas with
the cooled first stream and the cooled second stream to form a
cooled natural gas stream, wherein the natural gas is at a pressure
less than 5.5 MPa, wherein the cooling is carried out in at least
one heat exchanger selected from the group comprising a spiral
wound heat exchanger, a printed circuit heat exchanger and a spool
wound heat exchanger. Various sub-embodiments of this embodiment
may include any one or more of the following in any order: wherein
the natural gas pressure is less than 5 MPa; and wherein in the
natural gas pressure is less than 4.5 MPa.
[0038] According to still another embodiment of the present
invention there is provided a method for cooling natural gas with a
refrigerant. The method may include one or more of the following,
in any order. The method may include compressing and cooling the
refrigerant to a first pressure to form a compressed refrigerant.
The method may include splitting the compressed refrigerant into a
first stream and a second stream both at the first pressure. The
method may include cooling the first stream to form a cooled first
stream. The method may include expanding the cooled first stream to
a first expansion pressure to form an expanded first stream. The
method may include compressing the second stream to a second
pressure higher than the first pressure, forming a higher pressure
second stream. The method may include cooling the higher pressure
second stream to form a cooled second stream. The method may
include expanding the cooled second stream to a second expansion
pressure to form an expanded second stream. The method may include
cooling the natural gas with the expanded first stream and the
expanded second stream forming a heated second stream. In the
method at least one of the first expansion pressure and the second
expansion pressure are less than 1.18 MPa. Various sub-embodiments
of this embodiment may include any one or more of the following in
any order: wherein at least one of the first expansion pressure or
the second expansion pressure is less than 1.17 MPa; and wherein at
least one of the first expansion pressure or the second expansion
pressure is less than 1.16 MPa.
[0039] According to yet another embodiment of the present invention
there is provided a method for processing natural gas. The method
may include one or more of the following, in any order. The method
may include providing a first natural gas vapor stream to a
fractionation tower. The method may include providing a second
natural gas stream to the fractionation tower as a reflux stream.
The method may include separating the first natural gas vapor
stream into a heavy component liquid stream and a light component
vapor stream.
[0040] According to even still another embodiment of the present
invention, there is provided apparatus comprising part or all of
the apparatus disclosed to carry out any method or method step
disclosed herein.
BRIEF DESCRIPTION OF THE DRAWINGS
[0041] The following drawings illustrate some of the many possible
embodiments of this disclosure in order to provide a basic
understanding of this disclosure. These drawings do not provide an
extensive overview of all embodiments of this disclosure. These
drawings are not intended to identify key or critical elements of
the disclosure or to delineate or otherwise limit the scope of the
claims. The following drawings merely present some concepts of the
disclosure in a general form. Thus, for a detailed understanding of
this disclosure, reference should be made to the following detailed
description, taken in conjunction with the accompanying drawings,
in which like elements have been given like numerals.
[0042] FIG. 1 is a schematic representation of one non-limiting
embodiment 100 of a gas pretreatment process.
[0043] FIG. 2 is a schematic representation of one non-limiting
embodiment 200 for processing natural gas into liquefied natural
gas ("LNG").
[0044] FIG. 3 is a schematic representation of one non-limiting
embodiment 300 for processing natural gas into liquefied natural
gas ("LNG").
[0045] FIG. 4 is an isometric front view of brazed aluminum heat
exchanger 240.
[0046] FIG. 5 is an isometric back view of brazed aluminum heat
exchanger 240.
[0047] FIG. 6 is a front view of brazed aluminum heat exchanger
(BAHX) 240.
[0048] FIG. 7 is side views of brazed aluminum heat exchanger
(BAHX) 240.
DETAILED DESCRIPTION OF THE INVENTION
[0049] The present invention will find utility with a wide variety
of natural gas sources, and in a wide variety of
environments/locations. As a non-limiting example the present
invention is believed to have application both onshore and
offshore. Some embodiments of the present invention may be
particularly useful in the processing of gas fields or associated
gas from geographically remote or offshore locations for which
pipelines are not present or are cost prohibitive to install.
[0050] It should be understood that the proposed design operating
conditions (i.e., temperature, pressure, compositions, flowrates,
sizing, etc.) for the various process streams shown in FIGS. 1 and
2 can vary depending upon the composition of the input feed gas
being processed, equipment design variations, process design
variations, climactic factors, and the particular manner in which
the equipment and process are being operated. In addition,
conditions may also vary depending upon particular operating
goals/limitations, which force/require that any plant be operated
in a certain manner. Flowrates, of course, vary depending upon
plant capacity and size. It should also be noted that any
temperatures, pressures, flowrates, heating/cooling duties, and the
like, shown in FIGS. 1 and 2 and/or discussed herein, should be
considered merely design examples and may vary depending upon any
number of design/operational circumstances. It is to be understood
that values inside or outside those ranges could be utilized, given
particular circumstances.
[0051] It should be understood that the various physical components
of the present invention may be any that are well known to those of
skill in the art. The patentability of the apparatus of the present
invention does not reside in the patentablity of any single piece
of equipment, but rather in the unique and nonobvious arrangement
of the various pieces of equipment to form the overall apparatus or
portion of the apparatus. Likewise, individual process steps are
generally known to those of skill in the art. The patentability of
the process of the present invention does not reside in the
patentablity of any single process step, but rather in the unique
and nonobvious arrangement of the various process steps to form the
overall process or a portion of the process.
[0052] The terms "gas" (or "vapor") and "liquid" are used
throughout this document as is common in the industry. It should be
noted that streams which are above their critical pressure actually
exist in a single dense phase.
[0053] The present invention will now be discussed by reference to
FIG. 1, which is a schematic representation of one non-limiting
embodiment of a gas pretreatment process.
[0054] Natural gas stream 101 comprises raw untreated natural gas.
As used throughout the specification, natural gas is understood to
mean raw natural gas or treated natural gas. Raw natural gas
primarily comprises light hydrocarbons such as methane, ethane,
propane, butanes, pentanes, hexane and potentially other
hydrocarbons, but may also comprise small amounts of
non-hydrocarbon impurities, such as nitrogen, carbon dioxide,
hydrogen sulfide, carbonyl sulfide, various mercaptans or water,
and/or traces of helium. Treated natural gas primarily comprises
methane, ethane, and propane but may also comprise nitrogen and a
small percentage of heavier hydrocarbons such as butanes and
pentanes.
[0055] As non-limiting examples, natural gas may comprise as little
as 55 mole percent methane. However, it is preferable that the
natural gas suitable for this process comprises at least about 75
mole percent methane, more preferably at least about 85 mole
percent methane, and most preferably at least about 90 mole percent
methane for best results. Likewise, the exact composition of the
non-hydrocarbon impurities also varies depending upon the source of
the natural gas.
[0056] Consequently, it is often necessary to pretreat the natural
gas in one or more pretreatment processes 10 to reduce the
concentrations of non-hydrocarbon impurities such as acid gases,
mercury, and water that can freeze, plug lines and heat exchangers,
or otherwise damage equipment used in the process.
[0057] A common optional pretreatment 10 for gas stream 101
includes passing it through an amine absorber to remove carbon
dioxide. In addition to being corrosive, carbon dioxide will
solidify at cryogenic temperatures and cause operational problems
in the cryogenic liquefaction process. Stream 102 represents carbon
dioxide removed in pretreatment step 10.
[0058] Another common pretreatment 10 for gas stream 101 includes
dehydration to remove water that solidifies at cryogenic
temperatures. Stream 103 represents water removed in pretreatment
step 10.
[0059] Another common pretreatment 10 for gas stream 101 includes
passing it through a mercury guard bed, as mercury is corrosive to
the aluminum equipment commonly used in cryogenic operations. Even
if mercury is not detectable in the gas stream analysis, it is
generally preferred to guard against its presence.
[0060] Of course, impurities will vary from gas source to gas
source, and any other pretreatments as dictated by the impurities
of the particular gas source may be utilized.
[0061] In the embodiment as shown in FIG. 1, natural gas stream 115
is a treated gas stream, that is, it has been treated to remove
certain impurities as discussed above.
[0062] In some instances, it may be necessary to further pretreat
this natural gas to reduce the quantity of heavy hydrocarbon
components (typically hexane and heavier components, referred to as
C6+) in the gas, as these components may be disruptive in the
liquefaction process. Natural gas stream 115 from pretreatment 10
is mostly methane, with a few percent ethane and propane, a
fraction butanes, and some lesser amount of pentanes and C6+
components. In the non-limiting embodiment as shown, a scrubber
tower 12 is utilized to remove most of the C6+ components from the
gas. In some embodiments, the resulting natural gas stream 127
exiting the overhead of the scrubber tower may contain no more than
5 ppm by weight of C6+ components.
[0063] Natural gas stream 115 provided from pretreatment 10 may be
optionally split into primary stream 117 and a smaller gas stream
118. This split may be manually controlled, or may be subject to
automatic control based on conditions of the process. Gas stream
118 is introduced into the lower end of scrubber tower 12 to
provide vapor flow in the bottom section of the tower. Stream 118
may supplement or replace vapor that would otherwise be produced in
a conventional reboiler.
[0064] In a non-limiting embodiment as shown, a feed/product
exchanger 11 is utilized to cool the primary feed gas stream 117
and to warm the cold scrubber overhead product stream 127. Natural
gas stream 117 is cooled by exchanger 11 becoming cooled natural
gas stream 105, and is then introduced into the mid section of
scrubber 12. The use of exchanger 11 reduces the cooling duty that
would otherwise be required at tower 12. In a further optional
embodiment, feed/product exchanger 11 may be provided with any
suitable supplemental cooling not shown, whether a separate or
dedicated refrigerant stream or a recycle stream.
[0065] In the non-limiting embodiment as shown, reflux for scrubber
tower 12 may be generated utilizing substantially cooled natural
gas or LNG from one or more sources (as a non-limiting example,
stream 109 of FIG. 2), and bottom vapor is provided by gas stream
118. This configuration of this embodiment is relatively simple yet
effective and utilizes a small number of equipment items and
minimal process control. This simplicity is considered an advantage
for this configuration. Certainly the overhead cooling duty and
bottom heating duty may be provided by a wide variety of means and
methods, including a traditional overhead condenser (potentially
utilizing a refrigerant for cooling) and reboiler. Optionally, the
scrubber tower can be operated as a refluxed absorber, a reboiled
absorber, or even as a simple flash vessel.
[0066] The preferred operating pressure of the scrubber tower is
lower than the pressure of the feed gas to liquefaction, stream
110. In one non-limiting embodiment the scrubber tower operates
between 300 and 650 psig. While in some embodiments the scrubber
tower may be operated at pressures above or below this range, the
advantage of operating the scrubber tower in this pressure range
rather than a higher pressure is that the separation efficiencies
of the heavy components are improved at the lower operating
pressure. At lower operating pressures, equipment and piping will
be larger, increasing space requirements and capital costs.
[0067] In a further optional embodiment, feed/product exchanger 11
may also be utilized to pre-cool natural gas in pretreatment 10
upstream of dehydration to condense water and thus reduce the duty
on the dehydration equipment. As shown, a natural gas pretreatment
stream 111 is cooled in exchanger 11 exiting as a cooled stream
112. At knock out vessel 13 this stream 112 may be separated,
depending upon its composition, into water stream 113 and liquid
hydrocarbon stream 114, with a gas stream 116 returning to
pretreatment 10.
[0068] Scrubber bottoms stream 119 contains the separated C6+
components along with some pentanes, butanes, and lighter
components and may be used as fuel or treated further and/or sent
to storage depending upon the needs of the facility.
[0069] Scrubber overhead stream 127 is void of most C6+ components
and is quite cold. To provide cooling to the scrubber tower feed
gas, overhead stream 127 is routed through exchanger 11 exiting as
a warmer gas stream 128. This gas stream 128 may optionally be
routed to booster compression equipment 15 to produce a gas stream
110 of suitable pressure for feeding to the liquefaction process.
This pressure may be at, above or below the critical pressure of
the gas stream. In some embodiments the booster compressors will
provide a gas stream 110 with a pressure of about 800 psig.
[0070] As an option to the scrubber tower 12 upstream of
liquefaction process 200, any suitable optional process for removal
of NGL (ethane and heavier components) or LPG (propane and heavier
components) may be utilized.
[0071] Referring additionally to FIG. 2, there is shown a schematic
representation of one non-limiting embodiment 200 for processing
natural gas into liquefied natural gas ("LNG").
[0072] Natural gas feed stream 110 may have been optionally treated
to remove C6+ components in a process such as that of FIG. 1. This
natural gas feed stream 110 may have transited through compression
equipment to arrive at a certain desired pressure for processing.
In a non-limiting embodiment that processing pressure may be on the
order of 800 psig, although it should be understood that pressures
up to 1100 psig, 1200 psig, or perhaps even higher, or as low as
600 psig, 500 psig or even lower may be used. In some non-limiting
embodiments, in which main heat exchanger 240 comprises an aluminum
or brazed aluminum plate heat exchanger the pressure of stream 110
may be at least 5.5 MPa, greater than 5.5 MPa, greater than 6 MPa,
greater than 6.5 MPa, greater than 7 MPa, greater than 7.5 MPa, and
greater than 8 MPa. In some non-limiting embodiments, in which main
heat exchanger 240 comprises a printed circuit heat exchanger
(PCHE), spiral wound heat exchanger or spool wound heat exchanger
the pressure of stream 110 may be 5.5 MPa or less, less than 5.5
MPa, less than 5 MPa, less than 4.5 MPa, and less than 4 MPa.
[0073] Stream 110 then passes through main heat exchanger 240 where
it is significantly cooled, exiting as stream 211 at a temperature
on the order of -235 to -250 F. The temperature of stream 211 is
low enough that the stream becomes substantially liquefied when
later flashed (or expanded) to a pressure below its critical
pressure. Stream 211 may be split into stream 109 that is used to
provide reflux to scrubber tower 12 of FIG. 1, and stream 203 which
is released through a valve 241 to low pressure (near atmospheric)
stream 212 and sent to LNG storage or flash vessel 236. Valve 241
may be optionally replaced with or supplemented by an expander. A
small amount of flash gas is formed when stream 203 drops in
pressure and temperature across valve (or expander) 241. The
combined flash gas and any boil-off gas generated by heat in-leak
to the LNG storage or flash vessel 236 produces a cold,
low-pressure gas stream 212. In the embodiment shown, stream 212 is
boosted in pressure by blower 237 and the resulting stream 238 is
returned to the main heat exchanger 240 in order to recover its
cooling duty. Stream 238 (predominantly methane, nitrogen, and some
ethane) exits the main heat exchanger 240 as a significantly warmer
gas stream 239. In a typical embodiment, stream 239 may be
compressed for use as fuel gas to gas turbines used as process
drivers or for power generation. Any gas from stream 239 that
exceeds the amount needed for fuel gas may be optionally recycled
to the process upstream of the liquefaction equipment. By varying
the temperature of stream 211, more or less flash gas may be
produced. Optionally, the temperature of stream 211 may be
controlled such that stream 239 produces nearly or exactly the
quantity of fuel gas required by the facility. In another
embodiment, flash vessel 236 may be replaced with a nitrogen
scrubber tower to significantly reduce the nitrogen content of the
LNG product.
[0074] In the non-limiting embodiment as shown, cooling is provided
to main heat exchanger 240 by two joined refrigeration loops.
Certainly, any number of loops including at least 2, 3, 4, 5, 6, 7,
8, 9, 10, or more, may be utilized, and any suitable refrigerant
may be utilized. Non-limiting examples of suitable refrigerants
include nitrogen, air, argon, hydrocarbons, helium, suitable
cryogenic refrigerants, and mixtures of two or more thereof. A
preferred refrigerant comprises nitrogen and oxygen; a non-limiting
example includes nitrogen containing 0 to 21% oxygen by volume. In
the preferred embodiment, the refrigerant may remain in the gaseous
phase at all points in the process. This is an advantage
particularly for offshore applications in which the process
equipment is subject to tilt, roll, or other vessel motions, since
no distribution of a mixed-phase refrigerant is required. Some
embodiments of the present invention may utilize non-flammable
refrigerants. Optionally, in some embodiments, closed-loop
refrigeration may be added, either in combination with the heat
exchangers described here or in separate heat exchangers, to cool
the gas entering the liquefaction process or to cool the
refrigerant gas exiting the refrigerant compressors. The use of
separate closed-loop refrigerant may improve the energy efficiency
of the overall process. The refrigerant stream may be split into
two loops at piping split S and combined back together at piping
junction J.
[0075] Starting at piping junction J, the refrigerant stream 213 at
approximately ambient temperature (depending on the temperature of
the process cooling media, for example air, water, or chilled
water) undergoes a number of stages of compression with cooling
following each stage of compression.
[0076] In the example shown, refrigerant stream 213 is compressed
(and heated) by compressor 243 and exits as stream 214. Subsequent
cooling of stream 214 is provided by cooler 244 resulting in a
cooled stream 215. In the example shown, compressor 243 is driven
by expander 242.
[0077] Refrigerant stream 215 is compressed (and heated) by a
compressor stage 245 and exits as stream 216. Subsequent cooling of
stream 216 is provided by cooler 246 resulting in a cooled stream
217. Stream 217 is compressed (and heated) by compressor stage 247
and exits as stream 218. Subsequent cooling of stream 218 is
provided by cooler 249 resulting in a cooled stream 219. In one
non-limiting embodiment, the pressure of stream 219 is about 670
psig. In some non-limiting embodiments compressor stages 245 and
247 are typically driven by a single driver, examples of which may
include an electric motor, a gas turbine, aeroderivative gas
turbine, or a steam turbine.
[0078] Cooled refrigerant stream 219 is then split into two loops
at piping split S: a lower pressure, warmer loop beginning with
stream 220, and a higher pressure, cooler loop beginning with
stream 230. In the practice of the present invention, the higher
pressure lower temperature refrigerant loop is further compressed
to a pressure substantially higher than that of stream 220.
[0079] Cooling may be provided to coolers 244, 246, 249, and 252 by
any suitable means and method, and by using any suitable cooling
medium. There may be one or more cooling systems that service these
coolers. In one non-limiting embodiment, cooling water is provided
to each of those coolers.
[0080] With reference now to the lower pressure warmer loop, stream
220 is cooled in main heat exchanger 240, exiting as stream 221.
Expansion of stream 221 through expander 242 provides a cooler
stream 222. This stream 222 provides cooling to main heat exchanger
240, exiting as stream 223. The temperatures of stream 221 and 222
will vary depending on many factors including but not limited to
the composition of the gas being liquefied and the efficiency of
expander 242. A typical temperature range for stream 221 is -5 to
30 F and a typical temperature range for stream 222 is between -145
and -120 F. Similarly, the pressure of stream 222 may vary. In one
non-limiting embodiment, the pressure of stream 222 is about 150
psig.
[0081] With reference now to the higher pressure cooler loop,
stream 230 is now further compressed by compressor 251 forming
compressed stream 231, which is then subsequently cooled by cooler
52, exiting as cooled stream 232. In the example shown, compressor
251 is driven by expander 250. Stream 232 is cooled in main heat
exchanger 240, exiting as stream 233. Expansion of stream 233
through expander 250 provides a cooler stream 234. This stream 234
provides cooling to main heat exchanger 240, exiting as stream 235.
The advantage of the additional compression step 251 is that stream
232 does not need to be cooled in exchanger 240 to as low a
temperature at stream 233 in order to achieve the required expander
outlet temperature for stream 234. By comparison, without
compression step 251, the pressure drop (and corresponding
temperature drop) would have been much less across expander 250,
meaning that the temperature of stream 233 would need to be
substantially lower to achieve the required temperature of expanded
stream 234. The temperatures of stream 233 and 234 will vary
depending on many factors including but not limited to the
composition of the gas being liquefied and the efficiency of
expander 250. In some non-limiting embodiments, a typical
temperature range for stream 233 is -80 to -110 F and a typical
temperature range for stream 234 is between -235 and -265 F.
Similarly, the pressure of stream 234 may vary. In one non-limiting
embodiment, the pressure of stream 234 is about 150 psig.
[0082] The pressure of stream 232 entering main heat exchanger may
be any suitable desired pressure. In some non-limiting embodiments,
in which main heat exchanger 240 comprises an aluminum or brazed
aluminum plate heat exchanger the pressure of stream 232 may be at
least 5.5 MPa, greater than 5.5 MPa, greater than 6 MPa, greater
than 6.5 MPa, greater than 7 MPa, greater than 7.5 MPa, and greater
than 8 MPa. In some non-limiting embodiments, in which main heat
exchanger 240 comprises a printed circuit heat exchanger (PCHE) the
pressure of stream 232 may be 5.5 MPa or less, less than 5.5 MPa,
less than 5 MPa, less 4.5 MPa, and less than 4 MPa.
[0083] After being warmed in main heat exchanger 240, lower
pressure warmer loop stream 223 and higher pressure cooler loop 235
are combined together at piping junction J. It should be understood
that streams 222 and 234 should be expanded to approximately the
same expansion pressure so that streams 223 and 235 can be joined
without additional controls and/or processing. By approximately the
same expansion pressure it is meant within 0.05 MPa, 0.1 MPa, 0.15
MPa, 0.2 MPa, or 0.25 Mpa. Certainly the closer the expansion
pressures the more readily the streams may be joined without having
to adjust for pressure differences. In some embodiments, the
expansion pressures will be less than 1.18 MPa, less the 1.17 MPa,
less than 1.16 MPa, less the 1.15 MPa, less than 1.14 MPa, less the
1.13 MPa, less than 1.12 MPa, less the 1.11 MPa, and less than 1.10
MPa. Refrigerant makeup 224 may be provided as necessary to
maintain the overall refrigerant inventory.
[0084] In the practice of the present invention, any suitable heat
exchanger may be utilized for main heat exchanger 240. One
non-limiting example of a suitable heat exchanger includes an
aluminum plate heat exchanger (also known as an aluminum plate fin
heat exchanger or brazed aluminum heat exchanger) 240 as shown in
FIGS. 4-7. An non-limiting example of a suitable aluminum plate
heat exchanger includes those discloses in U.S. Pat. Application
entitled Brazed Aluminum Heat Exchanger With Split Core
Arrangement, filed on even date herewith by David A. Franklin et
al., which application is hereby incorporated by reference.
[0085] FIGS. 4 and 5 are isometric front and back views of brazed
aluminum heat exchanger 240. FIGS. 6 and 7 are front and side views
of brazed aluminum heat exchanger (BAHX) 240. The piping numbers
correspond to stream numbers in FIG. 2. In the non-limiting
embodiment as shown, the various streams enter and exit through the
center of heat exchanger 240, with BAHX cores 281 and 283 on one
side, and BAHX cores 282 and 284 on the other side. Various
manifolds for each incoming and outgoing stream are connected to
each of the cores. Specifically, each of pipes 110, 239, 232, 220,
221, 232, 233, 234, 211, 238 and 222, have corresponding manifolds
110M, 239M, 232M, 220M, 221M, 232M, 233M, 234M, 211M, 238M and
222M, respectively as shown. Exit piping 213 receives flow from
internal piping 235 and 223. Both piping 235 and 223 have
respective manifolds 235M and 223M.
[0086] In some embodiments, if gas stream 110 is at substantially
lower temperature than shown in the above example, the relative
flow rates, temperature, and/or pressure of the lower pressure and
the higher pressure refrigerant loops may change from what is
described in the example.
EXAMPLES
[0087] The following tables show computer modeling results for one
example of the process of the present invention as shown in FIG. 1
and FIG. 2.
TABLE-US-00001 Stream Number 101 102 103 105 109 Vapour Fraction
1.000 1.000 0.000 0.996 0.000 Temperature [C] 37.8 37.8 15.0 -45.6
-150.8 Pressure [bar] 35.5 35.5 31.4 33.1 55.8 Molar Flow [MMSCFD]
83.8 0.7 0.0 78.8 1.5 Mass Flow [kg/h] 74813 1537 41 69465 1318
Molecular Weight 17.9 44.0 18.0 17.7 17.6 Mole Frac Nitrogen
0.00959 0.00000 0.00000 0.00969 0.00971 Mole Frac O2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac CO2 0.00837 1.00000
0.00000 0.00000 0.00000 Mole Frac H2O 0.00206 0.00000 1.00000
0.00000 0.00000 Mole Frac Methane 0.89367 0.00000 0.00000 0.90310
0.90428 Mole Frac Ethane 0.07067 0.00000 0.00000 0.07141 0.07137
Mole Frac Propane 0.01010 0.00000 0.00000 0.01020 0.01009 Mole Frac
i-Butane 0.00406 0.00000 0.00000 0.00410 0.00379 Mole Frac n-Butane
0.00067 0.00000 0.00000 0.00067 0.00057 Mole Frac i-Pentane 0.00033
0.00000 0.00000 0.00034 0.00015 Mole Frac n-Pentane 0.00016 0.00000
0.00000 0.00016 0.00004 Mole Frac n-Hexane 0.00014 0.00000 0.00000
0.00014 0.00000 Mole Frac n-Heptane + 0.00019 0.00000 0.00000
0.00019 0.00000
TABLE-US-00002 Stream Number 110 111 112 113 114 Vapour Fraction
1.000 1.000 0.998 0.000 0.000 Temperature [C] 37.8 37.8 15.0 15.0
15.0 Pressure [bar] 56.2 35.5 35.1 35.1 35.1 Molar Flow [MMSCFD]
84.3 83.1 83.1 0.1 0.0 Mass Flow [kg/h] 74044 73276 73276 114 0
Molecular Weight 17.6 17.7 17.7 18.0 58.0 Mole Frac Nitrogen
0.00971 0.00967 0.00967 0.00000 0.00146 Mole Frac O2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac CO2 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00208 0.00208
0.99999 0.00056 Mole Frac Methane 0.90428 0.90122 0.90122 0.00000
0.37505 Mole Frac Ethane 0.07137 0.07126 0.07126 0.00000 0.13836
Mole Frac Propane 0.01009 0.01018 0.01018 0.00000 0.06281 Mole Frac
i-Butane 0.00379 0.00409 0.00409 0.00000 0.05871 Mole Frac n-Butane
0.00057 0.00067 0.00067 0.00000 0.01308 Mole Frac i-Pentane 0.00015
0.00034 0.00034 0.00000 0.01513 Mole Frac n-Pentane 0.00004 0.00016
0.00016 0.00000 0.00927 Mole Frac n-Hexane 0.00000 0.00014 0.00014
0.00000 0.02373 Mole Frac n-Heptane + 0.00000 0.00019 0.00019
0.00000 0.30183
TABLE-US-00003 Stream Number 115 116 117 118 119 Vapour Fraction
1.000 1.000 1.000 1.000 0.000 Temperature [C] 15.0 15.0 15.0 15.0
-2.5 Pressure [bar] 33.4 35.1 33.4 33.4 33.0 Molar Flow [MMSCFD]
82.9 83.0 78.8 4.1 0.1 Mass Flow [kg/h] 73121 73162 69465 3656 395
Molecular Weight 17.7 17.7 17.7 17.7 57.7 Mole Frac Nitrogen
0.00969 0.00969 0.00969 0.00969 0.00060 Mole Frac O2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac CO2 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00056 0.00000
0.00000 0.00000 Mole Frac Methane 0.90310 0.90259 0.90310 0.90310
0.18665 Mole Frac Ethane 0.07141 0.07137 0.07141 0.07141 0.09287
Mole Frac Propane 0.01020 0.01020 0.01020 0.01020 0.07891 Mole Frac
i-Butane 0.00410 0.00410 0.00410 0.00410 0.19092 Mole Frac n-Butane
0.00067 0.00067 0.00067 0.00067 0.06396 Mole Frac i-Pentane 0.00034
0.00034 0.00034 0.00034 0.11333 Mole Frac n-Pentane 0.00016 0.00016
0.00016 0.00016 0.07290 Mole Frac n-Hexane 0.00014 0.00014 0.00014
0.00014 0.08472 Mole Frac n-Heptane + 0.00019 0.00019 0.00019
0.00019 0.11514
TABLE-US-00004 Stream Number 127 128 203 210 211 Vapour Fraction
1.000 1.000 0.000 0.000 0.000 Temperature [C] -48.0 33.5 -150.8
-160.8 -150.8 Pressure [bar] 32.7 32.4 55.8 1.1 55.8 Molar Flow
[MMSCFD] 84.3 84.3 82.8 75.7 84.3 Mass Flow [kg/h] 74044 74044
72726 66694 74044 Molecular Weight 17.6 17.6 17.6 17.7 17.6 Mole
Frac Nitrogen 0.00971 0.00971 0.00971 0.00293 0.00971 Mole Frac O2
0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac CO2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac Methane 0.90428 0.90428 0.90428
0.90299 0.90428 Mole Frac Ethane 0.07137 0.07137 0.07137 0.07807
0.07137 Mole Frac Propane 0.01009 0.01009 0.01009 0.01104 0.01009
Mole Frac i-Butane 0.00379 0.00379 0.00379 0.00415 0.00379 Mole
Frac n-Butane 0.00057 0.00057 0.00057 0.00062 0.00057 Mole Frac
i-Pentane 0.00015 0.00015 0.00015 0.00016 0.00015 Mole Frac
n-Pentane 0.00004 0.00004 0.00004 0.00004 0.00004 Mole Frac
n-Hexane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Heptane + 0.00000 0.00000 0.00000 0.00000 0.00000
TABLE-US-00005 Stream Number 212 213 214 215 216 Vapour Fraction
1.000 1.000 1.000 1.000 1.000 Temperature [C] -160.8 35.0 84.3 37.8
99.1 Pressure [bar] 1.1 10.8 16.2 15.7 26.8 Molar Flow [MMSCFD] 7.1
523.5 523.5 523.5 523.5 Mass Flow [kg/h] 6032 735607 735607 735607
735607 Molecular Weight 17.0 28.2 28.2 28.2 28.2 Mole Frac Nitrogen
0.08180 0.95000 0.95000 0.95000 0.95000 Mole Frac O2 0.00000
0.05000 0.05000 0.05000 0.05000 Mole Frac CO2 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00000 0.00000
0.00000 0.00000 Mole Frac Methane 0.91805 0.00000 0.00000 0.00000
0.00000 Mole Frac Ethane 0.00015 0.00000 0.00000 0.00000 0.00000
Mole Frac Propane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
i-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac n-Butane
0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac i-Pentane 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac n-Pentane 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac n-Hexane 0.00000 0.00000 0.00000
0.00000 0.00000 Mole Frac n-Heptane + 0.00000 0.00000 0.00000
0.00000 0.00000
TABLE-US-00006 Stream Number 217 218 219 220 221 Vapour Fraction
1.000 1.000 1.000 1.000 1.000 Temperature [C] 37.8 106.5 37.8 37.8
-7.8 Pressure [bar] 26.3 47.6 47.1 47.1 46.6 Molar Flow [MMSCFD]
523.5 523.5 523.5 360.5 360.5 Mass Flow [kg/h] 735607 735607 735607
506564 506564 Molecular Weight 28.2 28.2 28.2 28.2 28.2 Mole Frac
Nitrogen 0.95000 0.95000 0.95000 0.95000 0.95000 Mole Frac O2
0.05000 0.05000 0.05000 0.05000 0.05000 Mole Frac CO2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac Methane 0.00000 0.00000 0.00000
0.00000 0.00000 Mole Frac Ethane 0.00000 0.00000 0.00000 0.00000
0.00000 Mole Frac Propane 0.00000 0.00000 0.00000 0.00000 0.00000
Mole Frac i-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole
Frac n-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
i-Pentane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Pentane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Hexane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Heptane + 0.00000 0.00000 0.00000 0.00000 0.00000
TABLE-US-00007 Stream Number 222 223 230 231 232 Vapour Fraction
1.000 1.000 1.000 1.000 1.000 Temperature [C] -88.8 35.0 37.8 97.9
37.8 Pressure [bar] 11.4 10.8 47.1 76.7 76.2 Molar Flow [MMSCFD]
360.5 360.5 163.0 163.0 163.0 Mass Flow [kg/h] 506564 506564 229044
229044 229044 Molecular Weight 28.2 28.2 28.2 28.2 28.2 Mole Frac
Nitrogen 0.95000 0.95000 0.95000 0.95000 0.95000 Mole Frac O2
0.05000 0.05000 0.05000 0.05000 0.05000 Mole Frac CO2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac Methane 0.00000 0.00000 0.00000
0.00000 0.00000 Mole Frac Ethane 0.00000 0.00000 0.00000 0.00000
0.00000 Mole Frac Propane 0.00000 0.00000 0.00000 0.00000 0.00000
Mole Frac i-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole
Frac n-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
i-Pentane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Pentane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Hexane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Heptane + 0.00000 0.00000 0.00000 0.00000 0.00000
TABLE-US-00008 Stream Number 233 234 235 238 239 Vapour Fraction
1.000 1.000 1.000 1.000 1.000 Temperature [C] -69.4 -153.6 35.0
-134.0 35.0 Pressure [bar] 75.7 11.4 10.8 2.0 1.8 Molar Flow
[MMSCFD] 163.0 163.0 163.0 7.1 7.1 Mass Flow [kg/h] 229044 229044
229044 6032 6032 Molecular Weight 28.2 28.2 28.2 17.0 17.0 Mole
Frac Nitrogen 0.95000 0.95000 0.95000 0.08180 0.08180 Mole Frac O2
0.05000 0.05000 0.05000 0.00000 0.00000 Mole Frac CO2 0.00000
0.00000 0.00000 0.00000 0.00000 Mole Frac H2O 0.00000 0.00000
0.00000 0.00000 0.00000 Mole Frac Methane 0.00000 0.00000 0.00000
0.91805 0.91805 Mole Frac Ethane 0.00000 0.00000 0.00000 0.00015
0.00015 Mole Frac Propane 0.00000 0.00000 0.00000 0.00000 0.00000
Mole Frac i-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole
Frac n-Butane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
i-Pentane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Pentane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Hexane 0.00000 0.00000 0.00000 0.00000 0.00000 Mole Frac
n-Heptane + 0.00000 0.00000 0.00000 0.00000 0.00000
TABLE-US-00009 STREAM DESCRIPTIONS 101 Natural Gas upstream of
pretreatment 10 102 CO2 removed in pretreatment 10 103 H2O removed
in pretreatment 10 105 Cooled gas feed to scrubber tower 12 109
Substantially cooled natural gas or LNG used to provide reflux to
scrubber tower 12 110 Natural Gas stream to liquefaction process
111 Optional gas stream to be cooled prior to dehydration step in
pretreatment 10 112 Cooled gas stream to knockout vessel 13 113
Water collected in knockout vessel 13 114 Condensed hydrocarbons
(if any; none will form for many feed gas compositions) collected
in knockout vessel 13 115 Natural Gas downstream of pretreatment 10
116 Cooled gas from knockout vessel 13 to dehydration step in
pretreatment 10 117 Natural Gas from pretreatment 10, after takeoff
point for stream 118 118 Natural Gas to bottom of scrubber tower
(optional; in place of or in addition to vapor generated by tower
reboiler) 119 Bottom liquid product from scrubber tower 127 Cold
overhead vapor from scrubber tower 128 Warmed overhead vapor from
scrubber tower, downstream of feed/product exchanger 11 203
Substantially cooled natural gas downstream of main heat exchanger
240 (upstream of pressure drop, downstream of take-off point for
stream 109) 204 Low-pressure LNG/flash gas mixture entering LNG
storage or flash vessel 236 (not listed in table; comprised of
flash vapor 212 and LNG product 210) 210 LNG product at storage
conditions 211 Substantially cooled natural gas downstream of main
heat exchanger 212 Combined flash gas and boil-off gas (gas
generated due to heat in-leak) from LNG storage or flash vessel 236
213 Combined low pressure, warmed refrigerant gas streams to
compressor 243 214 Compressor 243 discharge gas 215 Compressor 243
discharge gas downstream of aftercooler 244 216 Compressor stage
245 discharge gas 217 Compressor stage 245 discharge gas downstream
of aftercooler 246 218 Compressor stage 247 discharge gas 219
Compressor stage 247 discharge gas downstream of aftercooler 249
220 Lower pressure warmer loop refrigerant gas from split S to main
heat exchanger 240 221 Lower pressure warmer loop refrigerant gas
from main heat exchanger 240 to expander 242 222 Lower pressure
warmer loop refrigerant gas from expander 242 to main heat
exchanger 240 223 Lower pressure warmer loop refrigerant gas from
main heat exchanger 240 to combine with higher pressure cooler loop
refrigerant gas at junction J 224 Make-up refrigeration gas to
closed loop. Normally no flow, not listed in table. 230 Higher
pressure cooler loop refrigerant gas from split S to compressor 251
231 Higher pressure cooler loop refrigerant gas discharge from
compressor 251 232 Higher pressure cooler loop refrigerant gas
discharge from compressor 251, downstream of aftercooler 252, to
main heat exchanger 240 233 Higher pressure cooler loop refrigerant
gas from main heat exchanger 240 to expander 250 234 Higher
pressure cooler loop refrigerant gas from expander 250 to main heat
exchanger 240 235 Higher pressure cooler loop refrigerant gas from
main heat exchanger 240 to combine with lower pressure warmer loop
refrigerant gas at junction J 238 Cold gas from booster blower (or
fan) 237 to main heat exchanger 240 239 Warmed gas from main heat
exchanger 240. This stream may typically be compressed for use as
fuel gas but all or a portion of the stream may be recycled to
upstream equipment
Equipment/Block Descriptions
TABLE-US-00010 [0088] 10 Pretreatment steps. May include (but is
not limited to) removal of CO2, H2S, COS, mercaptans, water, Hg 11
Scrubber Feed/Product Exchanger 12 Scrubber Tower 13 Knockout
vessel upstream of dehydration step in pretreatment 10 15 Optional
booster compressor and aftercooler for natural gas stream going to
liquefaction equipment 236 LNG storage tank or flash vessel 237
Booster blower (or fan) used to slightly raise pressure of combined
flash gas/boil off gas stream 212 240 Main liquefaction heat
exchanger. 241 Joule-Thomson valve for pressure drop of cold
(typically dense phase) LNG from main liquefaction heat exchanger
240 to LNG storage or flash vessel 236. Note that this valve may
optionally be replaced by or supplemented by an expander. 242
Expander for lower pressure warmer loop refrigerant gas; drives
compressor 243. 243 Compressor for combined refrigerant stream 213
exiting main heat exchanger; driven by expander 242 244 Cooler for
discharge gas from compressor 243 245 First stage of main
refrigerant compressor 246 Cooler for discharge gas from compressor
245 247 Second stage of main refrigerant compressor 248 Driver for
2 stages of main refrigerant compression 245 and 247 249 Cooler for
discharge gas from compressor 247 250 Expander on higher pressure
cooler loop refrigerant gas; drives compressor 251 251 Compressor
on higher pressure cooler loop refrigerant gas, driven by expander
250 252 Cooler for discharge gas from compressor 247
[0089] Another non-limiting optional embodiment 300 is shown in
FIG. 3. In this embodiment 300, a scrubber tower for the removal of
C6+ components is integrated with the liquefaction process. This
may take the place of a scrubber tower upstream of the liquefaction
process as shown in FIG. 1.
[0090] The refrigeration circuit (streams and equipment 109 and 210
thru 252) are the same as described earlier for FIG. 2. However the
main heat exchanger 240 has been modified with additional streams
and is renamed 340.
[0091] Stream 300 represents pretreated gas for which
non-hydrocarbon impurities such as acid gases, mercury, and water
have been removed. Stream 300 may optionally be split into a
primary stream 300A and smaller secondary stream 305. Stream 300A
passes through main heat exchanger 340 where it is cooled to a
temperature at which the exiting stream 301 is partially liquefied,
but is above the temperature at which C6+ components will start to
solidify. In a typical embodiment, stream 301 comprises between
0.05% and 15% liquid. Stream 301 enters a scrubber tower 320. The
liquid product 303 from the scrubber tower 320 is removed and may
be used as fuel or processed further and stored.
[0092] Optionally, stream 305 may be introduced into the bottom of
scrubber tower 12 to provide vapor flow upward in the lower portion
of the tower. Stream 305 may supplement or replace vapor that would
otherwise be produced in a conventional reboiler.
[0093] The vapor product 302 from scrubber tower 320 passes through
main heat exchanger 340 where it is significantly cooled, exiting
as stream 211 at a temperature on the order of -235 to -250 F.
Stream 211 may be split into stream 109 that is raised in pressure
via pump 310 and used to provide reflux to scrubber tower 320, and
stream 203 which is released through a valve or expander 241 to low
pressure (near atmospheric) stream 212 and sent to LNG storage or
flash vessel 236. As another option, reflux for the tower may be
generated by cooling and partially condensing all or a portion of
the scrubber tower overhead vapor stream, using the liquid of the
cooled stream as reflux, and returning the vapor portion to the
main heat exchanger for the final cooling pass. This can be
performed via a separate heat exchanger or as a further
modification to main heat exchanger 340. The remainder of the
streams and equipment shown in FIG. 3 are the same as described
earlier for FIG. 2.
[0094] The present disclosure is to be taken as illustrative rather
than as limiting the scope or nature of the claims below. Numerous
modifications and variations will become apparent to those skilled
in the art after studying the disclosure, including use of
equivalent functional and/or structural substitutes for elements
described herein, use of equivalent functional couplings for
couplings described herein, and/or use of equivalent functional
actions for actions described herein. Any insubstantial variations
are to be considered within the scope of the claims below.
* * * * *