U.S. patent application number 11/224747 was filed with the patent office on 2007-03-15 for enhanced heavies removal/lpg recovery process for lng facilities.
Invention is credited to Weldon L. Ransbarger.
Application Number | 20070056318 11/224747 |
Document ID | / |
Family ID | 37853686 |
Filed Date | 2007-03-15 |
United States Patent
Application |
20070056318 |
Kind Code |
A1 |
Ransbarger; Weldon L. |
March 15, 2007 |
Enhanced heavies removal/LPG recovery process for LNG
facilities
Abstract
A LNG facility, and operating method therefor, capable of more
efficiently and/or effectively removing heavy hydrocarbon
components from the processed natural gas stream and recovering the
removed heavy components as LPG.
Inventors: |
Ransbarger; Weldon L.;
(Houston, TX) |
Correspondence
Address: |
ConocoPhilips Company - I.P. Legal
PO BOX 2443
BARTLESVILLE
OK
74005
US
|
Family ID: |
37853686 |
Appl. No.: |
11/224747 |
Filed: |
September 12, 2005 |
Current U.S.
Class: |
62/611 ;
62/620 |
Current CPC
Class: |
F25J 2230/08 20130101;
F25J 1/0265 20130101; F25J 3/0209 20130101; F25J 1/0035 20130101;
F25J 2245/02 20130101; F25J 1/0022 20130101; F25J 1/0045 20130101;
F25J 2270/02 20130101; F25J 1/021 20130101; F25J 2200/04 20130101;
F25J 2230/60 20130101; F25J 2270/12 20130101; F25J 1/0238 20130101;
F25J 2200/78 20130101; F25J 1/0052 20130101; F25J 2200/74 20130101;
F25J 1/004 20130101; F25J 2205/02 20130101; F25J 3/0238 20130101;
F25J 2235/60 20130101; F25J 2210/06 20130101; F25J 2205/04
20130101; F25J 2200/72 20130101; F25J 2270/60 20130101; F25J 3/0233
20130101; F25J 2240/02 20130101 |
Class at
Publication: |
062/611 ;
062/620 |
International
Class: |
F25J 3/00 20060101
F25J003/00; F25J 1/00 20060101 F25J001/00 |
Claims
1. A process for liquefying a natural gas stream, said process
comprising: (a) using a first distillation column to separate at
least a portion of said natural gas stream into a first relatively
more volatile fraction and a first relatively less volatile
fraction; (b) using a second distillation column to separate at
least a portion of said first relatively less volatile fraction
into a second relatively more volatile fraction and a second
relatively less volatile fraction, said second distillation column
operating at a lower pressure than said first distillation column;
(c) using a reflux portion of said second relatively more volatile
fraction as reflux in said first and/or second distillation
columns; and (d) cooling at least a portion of said reflux portion
via indirect heat exchange with at least a portion of said first
relatively less volatile fraction.
2. The process of claim 1, said second distillation column being
operated at a pressure at least about 25 psi less than the
operating pressure of said first distillation column.
3. The process of claim 1, said second distillation column being
operated at a pressure at least about 100 psi less than the
operating pressure of said first distillation column.
4. The process of claim 1, said at least a portion of said natural
gas stream separated in said first distillation column having a
vapor fraction greater than about 0.7 on a molar basis when
introduced into said first distillation column.
5. The process of claim 1; and (e) prior to step (a), condensing a
portion of said natural gas stream; (f) prior to step (a) and
subsequent to step (e), separating said natural gas stream into a
predominately vapor stream and a predominately liquid stream; and
(g) introducing at least a portion of said predominately vapor
stream into said first distillation column.
6. The process of claim 5, said first distillation column having at
least 5 theoretical stages, said at least a portion of said
predominately vapor stream introduced into said first distillation
column in accordance with step (g) entering said first distillation
column in or below one or more of the bottom 3 theoretical stages
of said first distillation column.
7. The process of claim 5; and (h) expanding said predominately
vapor stream prior to introduction into said first distillation
column, said expanding of step (h) causing at least a portion of
said predominately vapor stream to condense.
8. The process of claim 5; and (i) combining at least a portion of
said first relatively less volatile fraction with at least a
portion of said predominately liquid stream to thereby form a
combined stream; and (j) introducing at least a portion of said
combined stream into said second distillation column.
9. The process of claim 8, said combining of step (i) occurring
subsequent to using said first relatively less volatile fraction
for said cooling of step (d).
10. The process of claim 1; and (k) separating said reflux portion
into a first reflux stream and a second reflux stream; (l)
introducing said first reflux stream into an upper section of said
first distillation column; and (m) introducing said second reflux
stream into an upper section of said second distillation
column.
11. The process of claim 10, said separating of step (k) including
introducing at least a portion of said second relatively more
volatile fraction into a reflux accumulator vessel, removing a
liquid stream from said reflux accumulator, and removing a vapor
stream from said reflux accumulator, said liquid stream removed
from said reflux accumulator being said reflux portion.
12. The process of claim 11; and (n) combining at least a portion
of said vapor stream removed from said reflux accumulator with at
least a portion of said first relatively more volatile stream.
13. The process of claim 12; and (o) cooling the combined stream
resulting from step (n) in a methane refrigeration cycle employing
a predominately methane refrigerant.
14. The process of claim 10; and (p) prior to introduction into
said second distillation column, cooling said second reflux stream
via indirect heat exchange with a mechanical refrigeration
cycle.
15. The process of claim 14, said mechanical refrigeration cycle
employing a predominately ethylene or ethane refrigerant.
16. The process of claim 1; and (q) cooling at least a portion of
said first relatively more volatile fraction in a methane
refrigeration cycle employing a predominately methane
refrigerant.
17. The process of claim 1, said process being a cascade-type LNG
process.
18. The process of claim 17, said cascade-type LNG process
including an open methane refrigeration cycle.
19. The process of claim 1; and (r) vaporizing liquefied natural
gas produced by the process of claim 1.
20. A liquefied natural gas product produced by the process of
claim 1.
21. A computer-implemented simulation process comprising: using a
computer to simulate the process of claim 1.
22. A process for liquefying anatural gas stream, said process
comprising: (a) using a vapor/liquid separator to separate at least
a portion of said natural gas stream into a predominately vapor
separated portion and a predominately liquid separated portion; (b)
using a first distillation column to separate at least a portion of
said predominately vapor separated portion into a first relatively
more volatile fraction and a first relatively less volatile
fraction; (c) introducing a first reflux stream into an upper
section of said first distillation column; and (d) cooling at least
a portion of said first reflux stream via indirect heat exchange
with at least a portion of said predominately liquid separated
portion.
23. The process of claim 22; and (e) using at least a portion of
said first relatively less volatile fraction as said first reflux
stream.
24. The process of claim 22; and (f) using at least a portion of
said first relatively more volatile fraction as said first reflux
stream.
25. The process of claim 22; and (g) cooling at least a portion of
said first reflux stream via indirect heat exchange with at least a
portion of said first relatively less volatile fraction.
26. The process of claim 25; and (h) combining at least a portion
of said predominately liquid separated portion with at least a
portion of said first relatively less volatile fraction.
27. The process of claim 26, said combining of step (f) occurring
subsequent to using said predominately liquid separated stream and
said first relatively less volatile fraction for said cooling of
steps (d) and (g).
28. The process of claim 22; and (i) using a second distillation
column to separate at least a portion of said first relatively less
volatile fraction into a second relatively more volatile fraction
and a second relatively less volatile fraction.
29. The process of claim 28; and (j) using at least a portion of
said second relatively more volatile fraction as said first reflux
stream.
30. The process of claim 28; and (k) introducing a second reflux
stream into an upper section of said second distillation
column.
31. The process of claim 30; and (l) using a first portion of said
second relatively more volatile fraction as said first reflux
stream and a second portion of said second relatively more volatile
fraction as said second reflux stream.
32. The process of claim 28, said second distillation column being
operated a pressure that is at least about 25 psi less than the
operating pressure of said first distillation column.
33. The process of claim 22; and (m) prior to step (a), condensing
at least a portion of said natural gas stream; (n) prior to step
(a), separating said natural gas stream into a predominately vapor
stream and a predominately liquid stream; and (o) feeding at least
a portion of said predominately vapor stream to said first
distillation column.
34. The process of claim 33; and (p) expanding said predominately
vapor stream prior to introduction into said first distillation
column, said expanding of step (p) causing at least a portion of
said predominately vapor stream to condense.
35. The process of claim 22, said process being a cascade-type LNG
process.
36. The process of claim 22; and (q) vaporizing liquefied natural
gas produced by the process of claim 22.
37. A liquefied natural gas product produced by the process of
claim 22.
38. A computer-implemented simulation process comprising: using a
computer to simulate the process of claim 22.
39. A process for liquefying a natural gas stream, said process
comprising: (a) using a distillation column to separate at least a
portion of said natural gas stream into a relatively more volatile
fraction and a relatively less volatile fraction; (b) cooling at
least a portion of said relatively more volatile fraction in a
first heat exchange pass via indirect heat exchange with a first
refrigerant; (c) flashing at least a portion of the cooled
relatively more volatile fraction to thereby produce a flash gas;
(d) compressing at least a portion of said flash gas; and (e)
cooling at least a portion of the compressed flash gas in a second
heat exchange pass via indirect heat exchange with a second
refrigerant, said first and second heat exchange passes being
separate from one another.
40. The process of claim 39, said first and second refrigerants
comprising predominately propane, propylene, carbon dioxide,
ethane, ethylene, or methane.
41. The process of claim 39, said first and second refrigerants
comprising predominately ethylene or ethane.
42. The process of claim 39, said first and second refrigerants
being the same refrigerant.
43. The process of claim 39, said cooling of steps (b) and (e)
being carried out in a common heat exchanger.
44. The process of claim 43, said common heat exchanger being a
core-in-kettle type heat exchanger, said first heat exchange pass
being defined by a first core of said common heat exchanger, said
second heat exchange pass being defined by a second core of said
common heat exchanger.
45. The process of claim 39, (f) prior to step (a), cooling at
least a portion of said natural gas stream via indirect heat
exchanger with a second refrigerant; and (g) prior to step (e)
cooling at least a portion of said compressed flash gas via
indirect heat exchange with said second refrigerant.
46. The process of claim 45, said second refrigerant comprising
predominately propane, propylene, or carbon dioxide.
47. An apparatus for liquefying natural gas, said apparatus
comprising: a vapor/liquid separator having a vapor outlet and a
liquid outlet; a first distillation column fluidly coupled to said
vapor outlet and having a first overhead outlet and a first bottom
outlet; a heat exchanger having a heating pass and a cooling pass,
said heating and cooling passes being configured to facilitate
indirect heat exchange between fluids flowing therethrough, said
heating pass being fluidly coupled to said first bottom outlet; and
a second distillation column fluidly coupled to said heating pass
and having a second overhead outlet and a second bottom outlet,
said second overhead outlet being fluidly coupled to said cooling
pass.
48. The apparatus of claim 47; and an expander fluidly coupled
between said vapor outlet and said first distillation column.
49. The apparatus of claim 47, said first distillation column
including a first reflux inlet, said cooling pass being fluidly
coupled between said first reflux inlet and said second overhead
outlet.
50. The apparatus of claim 49, said second distillation column
including a second reflux inlet, said cooling pass being fluidly
coupled between said second reflux inlet and said second overhead
outlet.
51. The apparatus of claim 50; and a reflux accumulator fluidly
disposed between said cooling pass and said first and second reflux
inlets.
52. The apparatus of claim 47, said second heating pass being
fluidly coupled to said first bottom outlet.
53. The apparatus of claim 47, said heat exchanger having a second
heating pass, said second heating pass being fluidly coupled to
said first bottom outlet.
Description
BACKGROUND OF THE INVENTION
[0001] 1. Field of the Invention
[0002] This invention relates to a method and apparatus for
liquefying natural gas. In another aspect, the invention concerns a
liquefied natural gas (LNG) facility that provides more efficient
and/or effective removal of heavy hydrocarbon components from the
processed natural gas stream. In a further aspect, the invention
concerns an LNG facility that provides more efficient and/or
effective recovery of liquefied petroleum gas (LPG) from the
processed natural gas stream.
[0003] 2. Description of the Prior Art
[0004] The cryogenic liquefaction of natural gas is routinely
practiced as a means of converting natural gas into a more
convenient form for transportation and storage. Such liquefaction
reduces the volume of the natural gas by about 600-fold and results
in a product which can be stored and transported at near
atmospheric pressure.
[0005] Natural gas is frequently transported by pipeline from the
supply source to a distant market. It is desirable to operate the
pipeline under a substantially constant and high load factor but
often the deliverability or capacity of the pipeline will exceed
demand while at other times the demand may exceed the
deliverability of the pipeline. In order to shave off the peaks
where demand exceeds supply or the valleys when supply exceeds
demand, it is desirable to store the excess gas in such a manner
that it can be delivered when demand exceeds supply. Such practice
allows future demand peaks to be met with material from storage.
One practical means for doing this is to convert the gas to a
liquefied state for storage and to then vaporize the liquid as
demand requires.
[0006] The liquefaction of natural gas is of even greater
importance when transporting gas from a supply source which is
separated by great distances from the candidate market and a
pipeline either is not available or is impractical. This is
particularly true where transport must be made by ocean-going
vessels. Ship transportation in the gaseous state is generally not
practical because appreciable pressurization is required to
significantly reduce the specific volume of the gas. Such
pressurization requires the use of more expensive storage
containers.
[0007] In order to store and transport natural gas in the liquid
state, the natural gas is preferably cooled to -240.degree. F. to
-260.degree. F. where the liquefied natural gas (LNG) possesses a
near-atmospheric vapor pressure. Numerous systems exist in the
prior art for the liquefaction of natural gas in which the gas is
liquefied by sequentially passing the gas at an elevated pressure
through a plurality of cooling stages whereupon the gas is cooled
to successively lower temperatures until the liquefaction
temperature is reached. Cooling is generally accomplished by
indirect heat exchange with one or more refrigerants such as
propane, propylene, ethane, ethylene, methane, nitrogen, carbon
dioxide, or combinations of the preceding refrigerants (e.g., mixed
refrigerant systems). A liquefaction methodology which is
particularly applicable to the current invention employs an open
methane cycle for the final refrigeration cycle wherein a
pressurized LNG-bearing stream is flashed and the flash vapors
(i.e., the flash gas stream(s)) are subsequently employed as
cooling agents, recompressed, cooled, combined with the processed
natural gas feed stream and liquefied, thereby producing the
pressurized LNG-bearing stream.
[0008] During cooling ofthe processed natural gas stream in the LNG
facility, certain heavy hydrocarbon components are typically
removed in order to avoid freezing of these heavy components
(benzene in particular) in downstream heat exchangers. The removed
heavy hydrocarbon components can be further fractionated and used
as fuel gas and/or sold as liquefied petroleum gas (LPG). A variety
of schemes have been used in the past to remove heavies from the
processed natural gas stream and/or recover LPG from the stream.
However, many of the conventional systems are difficult and/or
expensive to operate. Further, many of the existing heavies
removal/LPG recovery systems do not recover enough LPG to be
economically feasible.
OBJECTS AND SUMMARY OF THE INVENTION
[0009] It is, therefore, an object of the present invention to
provide a system for efficiently and effectively removing heavy
hydrocarbon components from a natural gas stream undergoing
liquefaction in an LNG facility.
[0010] A further object of the present invention to provide a
system for efficiently and effectively recovering LPG from a
natural gas stream undergoing liquefaction in an LNG facility.
[0011] It should be understood that the above-listed objects are
only exemplary, and not all the objects listed above need be
accomplished by the invention described and claimed herein.
[0012] One embodiment of the present invention concerns a process
for liquefying a natural gas stream, the process comprising the
following steps: (a) using a first distillation column to separate
at least a portion of the natural gas stream into a first
relatively more volatile fraction and a first relatively less
volatile fraction; (b) using a second distillation column to
separate at least a portion of the first relatively less volatile
fraction into a second relatively more volatile fraction and a
second relatively less volatile fraction, the second distillation
column operating at a lower pressure than the first distillation
column; (c) using a reflux portion of the second relatively more
volatile fraction as reflux in the first and/or second distillation
columns; and (d) cooling at least a portion of the reflux portion
via indirect heat exchange with at least a portion of the first
relatively less volatile fraction.
[0013] Another embodiment of the present invention concerns a
process for liquefying a natural gas stream, the process comprising
the following steps: (a) using a vapor/liquid separator to separate
at least a portion of the natural gas stream into a predominately
vapor separated portion and a predominately liquid separated
portion; (b) using a first distillation column to separate at least
a portion of the predominately vapor separated portion into a first
relatively more volatile fraction and a first relatively less
volatile fraction; (c) introducing a first reflux stream into an
upper section of the first distillation column; and (d) cooling at
least a portion ofthe first reflux stream via indirect heat
exchange with at least a portion of the predominately liquid
separated portion.
[0014] Yet another embodiment of the present invention concerns a
process for liquefying a natural gas stream, the process comprising
the following steps: (a) using a distillation column to separate at
least a portion of the natural gas stream into a relatively more
volatile fraction and a relatively less volatile fraction; (b)
cooling at least a portion of the relatively more volatile fraction
in a first heat exchange pass via indirect heat exchange with a
first refrigerant; (c) flashing at least a portion of the cooled
relatively more volatile fraction to thereby produce a flash gas;
(d) compressing at least a portion ofthe flash gas; and (e) cooling
at least a portion of the compressed flash gas in a second heat
exchange pass via indirect heat exchange with the first
refrigerant, the first and second heat exchange passes being
separate from one another.
[0015] A further embodiment of the present invention concerns an
apparatus for liquefying natural gas. The apparatus includes a
vapor/liquid separator, a first distillation column, a heat
exchanger, and a second distillation column. The vapor/liquid
separator has a vapor outlet and a liquid outlet. The first
distillation column is fluidly coupled to the vapor outlet and has
a first overhead outlet and a first bottom outlet. The heat
exchanger has a heating pass and a cooling pass, the heating and
cooling passes are configured to facilitate indirect heat exchange
between fluids flowing therethrough. The heating pass is fluidly
coupled to the liquid outlet. The second distillation column is
fluidly coupled to the first bottom outlet and has a second
overhead outlet and a second bottom outlet. The cooling pass is
fluidly coupled to the second overhead outlet.
BRIEF DESCRIPTION OF THE DRAWING FIGURES
[0016] FIG. 1 is a simplified flow diagram Oman LNG facility
employing an improved system for removing heavies and recovering
LPG from the processed natural gas stream.
[0017] FIG. 2 is a is a simplified flow diagram of a first
alternative embodiment of the LNG facility.
[0018] FIG. 3 is a is a simplified flow diagram of a second
alternative embodiment of the LNG facility.
[0019] FIG. 4 is a is a simplified flow diagram of a third
alternative embodiment of the LNG facility.
[0020] FIG. 5 is a is a simplified flow diagram of a fourth
alternative embodiment of the LNG facility.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT
[0021] A cascaded refrigeration process uses one or more
refrigerants to transfer heat energy from a natural gas stream to
the refrigerants, and ultimately transferring the heat energy to
the environment. In essence, the overall refrigeration system
functions as a heat pump by removing heat energy from the natural
gas stream as the stream is progressively cooled to lower and lower
temperatures. The design of a cascaded refrigeration process
involves a balancing of thermodynamic efficiencies and capital
costs. In heat transfer processes, thermodynamic irreversibilities
are reduced as the temperature gradients between heating and
cooling fluids become smaller, but obtaining such small temperature
gradients generally requires significant increases in the amount of
heat transfer area, major modifications to various process
equipment, and the proper selection of flow rates through such
equipment so as to ensure that both flow rates and outlet
temperatures are compatible with the required heating/cooling
duty.
[0022] As used herein, the term "open-cycle cascaded refrigeration
process" refers to a cascaded refrigeration process comprising at
least one closed refrigeration cycle and one open refrigeration
cycle where the boiling point ofthe refrigerant employed in the
open cycle is less than the boiling point of the refrigerant
employed in the closed cycle and a portion of the cooling duty to
condense the compressed open-cycle refrigerant is provided by one
or more of the closed cycles. In one embodiment of the present
invention, a predominately methane stream is employed as the
refrigerant in the open cycle. This predominantly methane stream is
preferably derived from the processed natural gas feed stream and
can include compressed open methane cycle gas streams. As used
herein, the terms "predominantly," "primarily," "principally," and
"in major portion," when used to describe the presence of a
particular component of a fluid stream, shall mean that the fluid
stream is comprised of at least 50 mole percent of the stated
component. For example, a "predominantly" methane stream, a
"primarily" methane stream, a stream "principally" comprised of
methane, or a stream comprised "in major portion" of methane each
denote a stream comprised of at least 50 mole percent methane.
[0023] One of the most efficient and effective means of liquefying
natural gas is via an optimized cascade-type operation in
combination with expansion-type cooling. Such a liquefaction
process involves the cascade-type cooling of a natural gas stream
at an elevated pressure, (e.g., about 650 psia) by sequentially
cooling the gas stream via passage through a multistage propane
refrigeration cycle, a multistage ethane or ethylene refrigeration
cycle, and an open-end methane refrigeration cycle which utilizes a
portion of the feed gas as a source of methane and which includes
therein a multistage expansion cycle to further cool the same and
reduce the pressure to near-atmospheric pressure. In the sequence
of cooling cycles, the refrigerant having the highest boiling point
is utilized first followed by a refrigerant having an intermediate
boiling point and finally by a refrigerant having the lowest
boiling point. As used herein, the terms "upstream" and
"downstream" shall be used to describe the relative positions of
various components of an LNG facility along the main flow path of
natural gas through the facility.
[0024] Various pretreatment steps can be provided to remove certain
undesirable components, such as acid gases, mercaptans, mercury,
and moisture from the natural gas feed stream delivered to the LNG
facility. The composition of this gas stream may vary
significantly. As used herein, a natural gas stream is any stream
principally comprised of methane which originates in major portion
from a natural gas feed stream, such feed stream for example
containing at least 85 mole percent methane, with the balance being
ethane, higher hydrocarbons, nitrogen, carbon dioxide, and a minor
amount of other contaminants such as mercury, hydrogen sulfide, and
mercaptan. The pretreatment steps may be separate steps located
either upstream of the cooling cycles or located downstream of one
of the early stages of cooling in the initial cycle. The following
is a non-inclusive listing of some of the available means which are
readily known to one skilled in the art. Acid gases and to a lesser
extent mercaptans are routinely removed via a chemical reaction
process employing an aqueous amine-bearing solution. This treatment
step is generally performed upstream ofthe cooling stages in the
initial cycle. A major portion of the water is routinely removed as
a liquid via two-phase gas-liquid separation following gas
compression and cooling upstream of the initial cooling cycle and
also downstream ofthe first cooling stage in the initial cooling
cycle. Mercury is routinely removed via mercury sorbent beds.
Residual amounts of water and acid gases are routinely removed via
the use of properly selected sorbent beds such as regenerable
molecular sieves.
[0025] The pretreated natural gas feed stream is generally
delivered to the liquefaction process at an elevated pressure or is
compressed to an elevated pressure generally greater than 500 psia,
preferably about 500 psia to about 3,000 psia, still more
preferably about 500 psia to about 1,000 psia, still yet more
preferably about 600 psia to about 800 psia. The feed stream
temperature is typically near ambient to slightly above ambient. A
representative temperature range being 60 to 150.degree. F.
(10-65.degree. C.).
[0026] As previously noted, the natural gas feed stream is cooled
in a plurality of multistage refrigeration cycles (preferably
three) by indirect heat exchange with a plurality of different
refrigerants (preferably three). The overall cooling efficiency for
a given cycle improves as the number of stages increases but this
increase in efficiency is accompanied by corresponding increases in
net capital cost and process complexity. The feed gas is preferably
passed through an effective number of refrigeration stages,
nominally two, preferably two to four, and more preferably three
stages, in a first closed refrigeration cycle utilizing a
relatively high boiling refrigerant. Such relatively high boiling
point refrigerant is preferably comprised in major portion of
propane, propylene, carbon dioxide, or mixtures thereof, more
preferably the refrigerant comprises at least about 75 mole percent
propane, even more preferably at least 90 mole percent propane, and
most preferably the refrigerant consists essentially ofpropane.
Thereafter, the processed feed gas flows through an effective
number of stages, nominally two, preferably two to four, and more
preferably two or three, in a second closed refrigeration cycle in
heat exchange with a refrigerant having a lower boiling point. Such
lower boiling point refrigerant is preferably comprised in major
portion of ethane, ethylene, or mixtures thereof, more preferably
the refrigerant comprises at least about 75 mole percent ethylene,
even more preferably at least 90 mole percent ethylene, and most
preferably the refrigerant consists essentially of ethylene. Each
cooling stage comprises a separate cooling zone. As previously
noted, the processed natural gas feed stream is preferably combined
with one or more recycle streams (i.e., compressed open methane
cycle gas streams) at various locations in the second cycle thereby
producing a liquefaction stream. In the last stage of the second
cooling cycle, the liquefaction stream is condensed (i.e.,
liquefied) in major portion, preferably in its entirety, thereby
producing a pressurized LNG-bearing stream. Generally, the process
pressure at this location is only slightly lower than the pressure
of the pretreated feed gas to the first stage of the first
cycle.
[0027] The pressurized LNG-bearing stream is then further cooled in
a third refrigeration cycle referred to as the open methane cycle
via contact in a main methane economizer (heat exchanger) with
flash gases (i.e., flash gas streams) generated in this third cycle
via sequential expansion of the pressurized LNG-bearing stream to
near atmospheric pressure. The flash gases used as a refrigerant in
the third refrigeration cycle are preferably comprised in major
portion of methane, more preferably the flash gas refrigerant
comprises at least 75 mole percent methane, still more preferably
at least 90 mole percent methane, and most preferably the
refrigerant consists essentially of methane. During expansion of
the pressurized LNG-bearing stream to near atmospheric pressure,
the pressurized LNG-bearing stream is cooled via at least one,
preferably two to four, and more preferably three expansions where
each expansion employs an expander as a pressure reduction means.
Suitable expanders include, for example, either Joule-Thomson
expansion valves or hydraulic expanders. The expansion is followed
by a separation of the gas-liquid product with a separator. When a
hydraulic expander is employed and properly operated, the greater
efficiencies associated with the recovery of power, a greater
reduction in stream temperature, and the production of less vapor
during the flash expansion step will frequently more than off-set
the higher capital and operating costs associated with the
expander. In one embodiment, additional cooling of the pressurized
LNG-bearing stream prior to flashing is made possible by first
flashing a portion of this stream via one or more hydraulic
expanders and then via indirect heat exchange means employing said
flash gas stream to cool the remaining portion of the pressurized
LNG-bearing stream prior to flashing. The warmed flash gas stream
is then recycled via return to an appropriate location, based on
temperature and pressure considerations, in the open methane cycle
and will be recompressed.
[0028] Generally, the natural gas feed stream fed to the LNG
facility will contain such quantities of C.sub.3+ components so as
to result in the formation of a C.sub.3+ rich liquid in one or more
of the cooling stages. This liquid can be removed via gas-liquid
separation means. Generally, the sequential cooling ofthe natural
gas in each stage is controlled so as to remove as much of the
C.sub.3 and higher molecular weight hydrocarbons as possible from
the gas to produce a gas stream predominating in methane and a
liquid stream containing significant amounts of ethane and heavier
components. An effective number of gas/liquid separation means are
located at strategic locations downstream of the cooling zones for
the removal of liquids streams rich in C.sub.3+ components. The
exact locations and number of gas/liquid separation means will be
dependant on a number of operating parameters, such as the C.sub.3+
composition of the natural gas feed stream, the desired BTU content
ofthe LNG product, the value of the C.sub.3+ components for other
applications, and other factors routinely considered by those
skilled in the art of LNG plant and gas plant operation. The
C.sub.3+ hydrocarbon stream or streams may be demethanized via a
siLPGe stage flash or a fractionation column. In the latter case,
the resulting methane-rich stream can be directly returned at
pressure to the liquefaction process. In the former case, this
methane-rich stream can be repressurized and recycled or can be
used as fuel gas. The C.sub.3+ hydrocarbon stream or streams or the
demethanized C.sub.3+ hydrocarbon stream may be used as fuel or may
be further processed, such as by fractionation in one or more
fractionation zones to produce individual streams rich in specific
chemical constituents (e.g., C.sub.3, C.sub.4, and C.sub.5+).
[0029] The liquefaction process described herein may use one of
several types of cooling which include but are not limited to (a)
indirect heat exchange, (b) vaporization, and (c) expansion or
pressure reduction. Indirect heat exchange, as used herein, refers
to a process wherein the refrigerant cools the substance to be
cooled without actual physical contact between the refrigerating
agent and the substance to be cooled. Specific examples of indirect
heat exchange means include heat exchange undergone in a
shell-and-tube heat exchanger, a core-in-kettle heat exchanger, and
a brazed aluminum plate-fin heat exchanger. The physical state of
the refrigerant and substance to be cooled can vary depending on
the demands of the system and the type of heat exchanger chosen.
Thus, a shell-and-tube heat exchanger will typically be utilized.
where the refrigerating agent is in a liquid state and the
substance to be cooled is in a liquid or gaseous state or when one
ofthe substances undergoes a phase change and process conditions do
not favor the use of a core-in-kettle heat exchanger. As an
example, aluminum and aluminum alloys are preferred materials of
construction for the core but such materials may not be suitable
for use at the designated process conditions. A plate-fin heat
exchanger will typically be utilized where the refrigerant is in a
gaseous state and the substance to be cooled is in a liquid or
gaseous state. Finally, the core-in-kettle heat exchanger will
typically be utilized where the substance to be cooled is liquid or
gas and the refrigerant undergoes a phase change from a liquid
state to a gaseous state during the heat exchange.
[0030] Vaporization cooling refers to the cooling of a substance by
the evaporation or vaporization of a portion of the substance with
the system maintained at a constant pressure. Thus, during the
vaporization, the portion of the substance which evaporates absorbs
heat from the portion of the substance which remains in a liquid
state and hence, cools the liquid portion. Finally, expansion or
pressure reduction cooling refers to cooling which occurs when the
pressure of a gas, liquid or a two-phase system is decreased by
passing through a pressure reduction means. In one embodiment, this
expansion means is a Joule-Thomson expansion valve. In another
embodiment, the expansion means is either a hydraulic or gas
expander. Because expanders recover work energy from the expansion
process, lower process stream temperatures are possible upon
expansion.
[0031] The flow schematics set forth in FIGS. 1-4 represent
preferred embodiments of an inventive LNG facility providing
enhanced heavies removal and LPG recovery. Those skilled in the art
will recognize that FIGS. 1-4 are schematics only and, therefore,
many items of equipment that would be needed in a commercial plant
for successful operation have been omitted for the sake of clarity.
Such items might include, for example, compressor controls, flow
and level measurements and corresponding controllers, temperature
and pressure controls, pumps, motors, filters, additional heat
exchangers, and valves, etc. These items would be provided in
accordance with standard engineering practice.
[0032] To facilitate an understanding of FIGS. 1-4, the following
numbering nomenclature was employed. Items numbered 1 through 99
are process vessels and equipment which are associated with the
liquefaction process. Items numbered 100 through 199 correspond to
flow lines or conduits which contain predominantly methane streams.
Items numbered 200 through 299 correspond to flow lines or conduits
which contain predominantly ethylene streams. Items numbered 300
through 399 correspond to flow lines or conduits which contain
predominantly propane streams.
[0033] Referring to FIG. 1, gaseous propane is compressed in a
multistage (preferably three-stage) compressor 18 driven by a gas
turbine driver (not illustrated). The three stages of compression
preferably exist in a siLPGe unit although each stage of
compression may be a separate unit and the units mechanically
coupled to be driven by a siLPGe driver or combination of drivers.
Upon compression, the compressed propane is passed through conduit
300 to a cooler 20 where it is cooled and liquefied. A
representative pressure and temperature of the liquefied propane
refrigerant prior to flashing is about 100.degree. F. (38.degree.
C.) and about 190 psia. The stream from cooler 20 is passed through
conduit 302 to a pressure reduction means, illustrated as expansion
valve 12, wherein the pressure of the liquefied propane is reduced,
thereby evaporating or flashing a portion thereof. The resulting
two-phase product then flows through conduit 304 into a high-stage
propane chiller 2 wherein gaseous methane refrigerant introduced
via conduit 152, natural gas feed introduced via conduit 100, and
gaseous ethylene refrigerant introduced via conduit 202 are
respectively cooled via indirect heat exchange means 4,6, and 8,
thereby producing cooled gas streams respectively produced via
conduits 154, 102, and 204.
[0034] The vaporized propane gas from chiller 2 is returned to the
high-stage inlet port of compressor 18 through conduit 306. The
remaining liquid propane is passed through conduit 308, the
pressure further reduced by passage through a pressure reduction
means, illustrated as expansion valve 14, whereupon an additional
portion of the liquefied propane is flashed. The resulting
two-phase stream is then fed to an intermediate-stage propane
chiller 22 through conduit 310, thereby providing a coolant for
chiller 22. The cooled feed gas stream from chiller 2 flows via
conduit 102 to separation equipment 10 wherein gas and liquid
phases are separated. The liquid phase, which can be rich in
C.sub.3+ components, is removed via conduit 103. The gaseous phase
is removed via conduit 104 and fed to propane chiller 22. Ethylene
refrigerant from chiller 2 is introduced to chiller 22 via conduit
204.
[0035] In chiller 22, the feed gas stream, also referred to herein
as a methane-rich stream, and the ethylene refrigerant streams are
respectively cooled via indirect heat transfer means 24 and 26,
thereby producing cooled methane-rich and ethylene refrigerant
streams via conduits 110 and 206. The vaporized portion of the
propane refrigerant in chiller 22 is separated and passed through
conduit 311 to the intermediate-stage inlet of compressor 18.
Liquid propane refrigerant from chiller 22 is removed via conduit
314, flashed across a pressure reduction means, illustrated as
expansion valve 16, and then fed to a low-stage propane
chiller/condenser 28 via conduit 316.
[0036] As illustrated in FIG. 1, the methane-rich stream flows from
intermediate-stage propane chiller 22 to the low-stage propane
chiller 28 via conduit 110. In chiller 28, the methane-rich stream
is cooled via indirect heat exchange means 30. In a like manner,
the ethylene refrigerant stream flows from the intermediate-stage
propane chiller 22 to low-stage propane chiller 28 via conduit 206.
In the latter, the ethylene refrigerant is totally condensed or
condensed in nearly its entirety via indirect heat exchange means
32. The vaporized propane is removed from low-stage propane chiller
28 and returned to the low-stage inlet of compressor 18 via conduit
320.
[0037] As illustrated in FIG. 1, the methane-rich stream exiting
low-stage propane chiller 28 is introduced into high-stage ethylene
chiller 42 via conduit 112. Ethylene refrigerant exits low-stage
propane chiller 28 via conduit 208 and is preferably fed to a
separation vessel 37 wherein light components are removed via
conduit 209 and condensed ethylene is removed via conduit 210. The
ethylene refrigerant at this location in the process is generally
at a temperature of about -24.degree. F. (-31.degree. C.) and a
pressure of about 285 psia. The ethylene refrigerant then flows to
an ethylene economizer 34 wherein it is cooled via indirect heat
exchange means 38, removed via conduit 211, and passed to apressure
reduction means, illustrated as an expansion valve 40, whereupon
the refrigerant is flashed to a preselected temperature and
pressure and fed to high-stage ethylene chiller 42 via conduit 212.
Vaporized ethylene is removed from chiller 42 via conduit 214 and
routed to ethylene economizer 34 wherein the vapor functions as a
coolant via indirect heat exchange means 46. The ethylene vapor is
then removed from ethylene economizer 34 via conduit 216 and fed to
the high-stage inlet of ethylene compressor 48. The ethylene
refrigerant which is not vaporized in high-stage ethylene chiller
42 is removed via conduit 218 and returned to ethylene economizer
34 for further cooling via indirect heat exchange means 50, removed
from ethylene economizer via conduit 220, and flashed in a pressure
reduction means, illustrated as expansion valve 52, whereupon the
resulting two-phase product is introduced into a low-stage ethylene
chiller 54 via conduit 222.
[0038] The methane-rich stream introduced into high-stage ethylene
chiller 42 via conduit 112 is cooled in indirect heat exchange
means 44 and subsequently removed from high-stage ethylene chiller
42 via conduit 116. The stream in conduit 116 is then carried to a
low-stage ethylene chiller 54 wherein the methane-rich stream is
cooled and partially condensed in indirect heat exchange means 56.
The cooled and partially condensed methane-rich stream exiting
low-stage ethylene chiller 54 is directed to a phase separator 57
via conduit 160 for separation of the vapor and liquid fractions.
Phase separator 57 can be any equipment known in the art that is
capable of separating a stream containing vapor and liquid
fractions into two distinct vapor and liquid streams. A
predominately vapor stream exits an upper vapor outlet of phase
separator 57. This predominately vapor stream is carried to
expander 59 via conduit 162. In expander 59, the predominately
vapor stream is expanded and partially condensed to thereby form an
expanded stream that is transported to a first distillation column
60 via conduit 169. In a preferred embodiment of the present
invention, expander 59 is a hydraulic expander providing
substantially isentropic expansion of the predominately vapor
stream introduced therein. The expanded stream in conduit 169
preferably has a vapor fraction greater than about 0.7 on a molar
basis. More preferably the vapor fraction of the expanded stream in
conduit 169 is in the range of from about 0.8 to about 0.995, still
more preferably in the range of from about 0.9 to about 0.99, and
most preferably in the range of from 0.95 to 0.985 on a molar
basis.
[0039] First distillation column 60 is preferably equipped with
internals, such as trays and/or packing, disposed between a lower
section of column 60, where the predominately vapor expanded
feedstream is introduced, and an upper section of column 60, where
a liquid reflux stream is introduced as described in further detail
below. First distillation column 60 preferably provides at least
five theoretical stages, more preferably at least seven theoretical
stages, and most preferably in the range of from 9 to 20
theoretical stages. It is preferred for the expanded stream in
conduit 169 to be introduced into first distillation column 60 at a
location near the bottom of column 60. In particular, it is
preferred for a predominate portion of the expanded stream to be
introduced into first distillation column 60 in or below one or
more of the bottom three theoretical stages, more preferably in or
below one or more of the bottom two theoretically stages, and most
preferably in or below the bottom theoretical stage.
[0040] First distillation column 60 is operable to separate the
expanded stream introduced via conduit 169 into a first relatively
more volatile overhead vapor fraction produced via conduit 119 and
a first relatively less volatile bottom liquid fraction produced
via conduit 166. Typically, the relatively more volatile overhead
vapor fraction contains primarily methane (preferably >than 85
mole % methane), while the relatively less volatile bottom liquid
fraction contains primarily C.sub.2+ hydrocarbons. The methane-rich
overhead vapor fraction in conduit 119 is then combined with a
condensed flash gas stream in conduit 155, described in further
detail below, and the combined stream is carried to an ethylene
condenser 68 via conduit 120. The combined stream is cooled in a
indirect heat exchange means 70 of ethylene condenser 68 to thereby
produce a pressurized LNG-bearing stream which is produced via
conduit 122. Further processing ofthe LNG-bearing stream in conduit
122 is discussed in detail below.
[0041] The first relatively less volatile bottom liquid stream
exiting first distillation column 60 via conduit 166 is preferably
combined with the predominately liquid stream exiting the bottom
outlet of phase separator 57 via conduit 168. The combined liquid
stream is then conducted to a reflux condenser 63 via conduit 170.
In condenser 63, the combined stream from conduit 170 acts as a
coolant as it passes through indirect heat exchange means 64. Thus,
as the stream passes through indirect heat exchange means 64 it
cools the stream in indirect heat exchange means 67 by indirect
heat exchange. The cooling provided by the stream in heat exchange
means 64 warms the combined stream and, preferably, causes at least
a portion of the combined stream to vaporize. The warmed combined
stream is removed from reflux condenser 63 via conduit 174, which
carries the warmed combined stream to an inlet of a second
distillation column 65.
[0042] Second distillation column 65 is operable to separate the
combined stream from conduit 174 into a second relatively more
volatile overhead vapor fraction produced via conduit 176 and a
second relatively less volatile bottom liquid fraction produced via
conduit 400. The less volatile bottom liquid stream in conduit 400
preferably contains predominately C.sub.2+ hydrocarbons. The stream
in conduit 400 can be subjected to further separation to produce
LPG and/or various individual hydrocarbon components.
[0043] Second distillation column 65 includes an upper
rectification section disposed above the inlet of the combined
stream from conduit 174 and a lower reboiled section disposed below
the inlet of the combined stream from conduit 174. Second
distillation column 65 preferably includes upper internals, such as
packing and/or trays, disposed in the upper section ofthe column
and lower internals, such as packing and/or trays, disposed in the
lower section of the column. Second distillation column 65 is
preferably equipped with a reboiler 66 which removes a portion of
the liquid in the lower section of column 65, vaporizes the removed
liquid, and reintroduces the vaporized reboil stream into the lower
section of column 65 at a location below the location where the
liquid stream was removed. Further, second distillation column 65
includes an upper inlet for receiving a liquid reflux stream
introduced via conduit 184, as described in further detail
below.
[0044] It is preferred for second distillation column 65 to be
operated at a pressure that is less than the operating pressure of
first distillation column 60. Preferably, the operating pressure of
second distillation column 65 is at least about 25 psi less than
the operating pressure of first distillation column 60. Most
preferably, the operating pressure of second distillation column 65
is at least 100 psi less than the operating pressure of first
distillation column 60.
[0045] The second relatively more volatile overhead vapor fraction
produced from second distillation column 65 is transported to
reflux condenser 63 via conduit 176. As described above, the second
relatively more volatile fraction is cooled in indirect heat
exchanges means 67 via indirect heat exchange with the combined
stream passing through indirect heat exchange means 64. This
cooling in indirect heat exchange means 67 preferably condenses a
predominate portion ofthe second relatively more volatile fraction.
Conduit 178 removes the cooled second relatively more volatile
fraction from reflux condenser 63 and carries it to a reflux
accumulator vessel 69. Reflux accumulator vessel 69 can simply be a
substantially empty tank having a sufficient volume to account for
fluctuations in the rate of fluids supplied thereto and fluids
withdrawn therefrom.
[0046] A liquid reflux portion is preferably withdrawn from the
bottom of reflux accumulator vessel 69 via conduit 180. This liquid
reflux portion is then pumped, via cryogenic pump 73, to both the
first and second distillation columns 60,65 for use as liquid
reflux streams. The liquid reflux portion is discharged from pump
73 via conduit 182 and subsequently split into a first reflux
stream, which is carried to final ethylene chiller 68 via conduit
186, and a second reflux stream, which is carried to the upper
section of second distillation column 65 via conduit 184. The
second reflux stream in conduit 184 is introduced directly into the
upper section of second distillation column 65 as a liquid reflux
stream. The first reflux stream in conduit 186 undergoes further
cooling in indirect heat exchange means 75 of ethylene chiller 68
prior to introduction into an upper section of first distillation
column 60, via conduit 188, as a liquid reflux stream.
[0047] A vapor portion is withdrawn from reflux accumulator vessel
69 via conduit 190. This vapor portion is transported to main
methane economizer 74 and cooled in indirect heat exchange means 61
via indirect heat exchange with the flash gas streams described in
further detail below. The resulting cooled stream is withdrawn from
methane economizer 74 via conduit 192 and thereafter introduced
into a compressor 62. The resulting compressed stream is removed
from compressor 62 via conduit 194 and subsequently combined with a
compressed predominately-methane stream exiting main methane
compressor 83 via conduit 150, as described in further detail
below. In one embodiment of the present invention, compressor 62 is
powered by work generated in hydraulic expander 59. Compressor 62
and hydraulic expander 59 can be directly mechanically coupled to
one another. Alternatively, hydraulic expander 59 can drive a
generator (not shown) which provides electricity to a motor (not
shown) for driving compressor 62.
[0048] The gas exiting high-stage propane chiller 2 via conduit 154
is fed to main methane economizer 74 wherein the stream is cooled
via indirect heat exchange means 97. The stream cooled in heat
exchange mean 97 is removed from methane economizer 74 via conduit
155 and combined with the relatively more volatile overhead stream
from first distillation column 60 flowing in conduit 119. The
resulting combined stream is fed to ethylene chiller 68 via conduit
120. In ethylene chiller 68, this methane-rich stream is cooled and
condensed via indirect heat exchange means 70 with the liquid
effluent from low-stage ethylene chiller 54, which is routed to
ethylene chiller 68 via conduit 226. The vaporized ethylene from
low-stage ethylene chiller 54, withdrawn via conduit 224, and
ethylene chiller 68, withdrawn via conduit 228, are combined and
routed, via conduit 230, to ethylene economizer 34 wherein the
vapors finction as a coolant via indirect heat exchange means 58.
The stream is then routed via conduit 232 from ethylene economizer
34 to the low-stage inlet of ethylene compressor 48.
[0049] As illustrated in FIG. 1, the compressor effluent from vapor
introduced via the low-stage side of ethylene compressor 48 is
removed via conduit 234, cooled via inter-stage cooler 71, and
returned to compressor 48 via conduit 236 for injection with the
high-stage stream present in conduit 216. Preferably, the
two-stages are a siLPGe module although they may each be a separate
module and the modules mechanically coupled to a common driver. The
compressed ethylene product from compressor 48 is routed to a
downstream cooler 72 via conduit 200. The product from cooler 72
flows via conduit 202 and is introduced, as previously discussed,
to high-stage propane chiller 2.
[0050] The pressurized LNG-bearing stream, preferably a liquid
stream in its entirety, in conduit 122 is preferably at a
temperature in the range of from about -200 to about -50.degree. F.
(-130.degree. C. to -45.degree. C.), more preferably in the range
of from about -175 to about -100.degree. F. (-115.degree. C. to
-73.degree. C.), most preferably in the range of from -150 to
-125.degree. F. (-100.degree. C. to -85 .degree. C.). The pressure
of the stream in conduit 122 is preferably in the range of from
about 500 to about 700 psia, most preferably in the range of from
550 to 725 psia. The stream in conduit 122 is directed to main
methane economizer 74 wherein the stream is further cooled by
indirect heat exchange means/heat exchanger pass 76 as hereinafter
explained. It is preferred for main methane economizer 74 to
include a plurality of heat exchanger passes which provide for the
indirect exchange of heat between various predominantly methane
streams in the economizer 74. Preferably, methane economizer 74
comprises one or more plate-fin heat exchangers. The cooled stream
from heat exchanger pass 76 exits methane economizer 74 via conduit
124. The pressure of the stream in conduit 124 is then reduced by a
pressure reduction means, illustrated as expansion valve 78, which
evaporates or flashes a portion of the gas stream thereby
generating a two-phase stream. The two-phase stream from expansion
valve 78 is then passed to high-stage methane flash drum 80 where
it is separated into a flash gas stream discharged through conduit
126 and a liquid phase stream (i.e., pressurized LNG-bearing
stream) discharged through conduit 130. The flash gas stream is
then transferred to main methane economizer 74 via conduit 126
wherein the stream finctions as a coolant in heat exchanger pass
82. The predominantly methane stream is warmed in heat exchanger
pass 82, at least in part, by indirect heat exchange with the
predominantly methane stream in heat exchanger pass 76. The warmed
stream exits heat exchanger pass 82 and methane economizer 74 via
conduit 128.
[0051] The liquid-phase stream exiting high-stage flash drum 80 via
conduit 130 is passed through a second methane economizer 87
wherein the liquid is further cooled by downstream flash vapors via
indirect heat exchange means 88. The cooled liquid exits second
methane economizer 87 via conduit 132 and is expanded or flashed
via pressure reduction means, illustrated as expansion valve 91, to
further reduce the pressure and, at the same time, vaporize a
second portion thereof. This two-phase stream is then passed to an
intermediate-stage methane flash drum 92 where the stream is
separated into a gas phase passing through conduit 136 and a liquid
phase passing through conduit 134. The gas phase flows through
conduit 136 to second methane economizer 87 wherein the vapor cools
the liquid introduced to economizer 87 via conduit 130 via indirect
heat exchanger means 89. Conduit 138 serves as a flow conduit
between indirect heat exchange means 89 in second methane
economizer 87 and heat exchanger pass 95 in main methane economizer
74. The warmed vapor stream from heat exchanger pass 95 exits main
methane economizer 74 via conduit 140 and is conducted to the
intermediate-stage inlet of methane compressor 83.
[0052] The liquid phase exiting intermediate-stage flash drum 92
via conduit 134 is further reduced in pressure by passage through a
pressure reduction means, illustrated as a expansion valve 93.
Again, a third portion of the liquefied gas is evaporated or
flashed. The two-phase stream from expansion valve 93 is passed to
a final or low-stage flash drum 94. In flash drum 94, a vapor phase
is separated and passed through conduit 144 to second methane
economizer 87 wherein the vapor functions as a coolant via indirect
heat exchange means 90, exits second methane economizer 87 via
conduit 146, which is connected to the first methane economizer 74
wherein the vapor functions as a coolant via heat exchanger pass
96. The warmed vapor stream from heat exchanger pass 96 exits main
methane economizer 74 via conduit 148 and is conducted to the
low-stage inlet of compressor 83. The liquid stream exiting the
bottom of low-stage flash drum 94 via conduit 142 is liquefied
natural gas (LNG) at approximately atmospheric pressure. The
resulting LNG can then be stored and/or transported, and
subsequently vaporized as needed for use as gaseous natural
gas.
[0053] As shown in FIG. 1, the high, intermediate, and low stages
of compressor 83 are preferably combined as siLPGe unit. However,
each stage may exist as a separate unit where the units are
mechanically coupled together to be driven by a siLPGe driver. The
compressed gas from the low-stage section passes through an
inter-stage cooler 85 and is combined with the intermediate
pressure gas in conduit 140 prior to the second-stage of
compression. The compressed gas from the intermediate stage of
compressor 83 is passed through an inter-stage cooler 84 and is
combined with the high pressure gas provided via conduit 128 prior
to the third-stage of compression. The compressed gas (i.e.,
compressed open methane cycle gas stream) is discharged from high
stage methane compressor through conduit 150, is cooled in cooler
86, and is routed to the high pressure propane chiller 2 via
conduit 152 as previously discussed.
[0054] FIG. 2 illustrates a first alternative embodiment ofthe
present invention. The LNG facility shown in FIG. 2 is very similar
to the facility illustrated in FIG. 1. Therefore, common components
of FIG. 1 and FIG. 2 are identified with the same reference
numerals, and the written description of these components provided
above with reference to FIG. 1 also applies to FIG. 2. There are
two main differences between the embodiment illustrated in FIG. 2
and the embodiment illustrated in FIG. 1. The first difference is
the substitution of an expansion valve 77 (FIG. 2) for hydraulic
expander 59 (FIG. 1) between the upper outlet of phase separator 57
and the inlet of first distillation column 60. The second
difference is that in the embodiment of FIG. 2, reflux condenser 63
is modified to include an additional indirect heat exchange means
79. This additional heat exchange pass 79 allows the separated
liquid stream exiting the bottom of phase separator 57 via conduit
170 and the first relatively less volatile bottom liquid fraction
exiting first distillation column 60 via conduit 196 to finction as
coolants in separate heat exchange means 64 and 79. After use as
separate coolants in reflux condenser 63, the warmed streams from
indirect heat exchange means 64 and 79 can be combined and routed
to the inlet of second distillation column 65 via conduit 174. The
use of two separate heat exchange means 64 and 79 can improve the
efficiency of reflux condenser 63.
[0055] FIG. 3 illustrates a second alternative embodiment of the
present invention. The LNG facility shown in FIG. 3 is very similar
to the facilities illustrated in FIGS. 1 and 2. Therefore, common
components of FIGS. 1-3 are identified with the same reference
numerals, and the written description of these components provided
above with reference to FIGS. 1 and 2 also applies to FIG. 3. The
main difference between the embodiment illustrated in FIG. 3 and
the embodiments illustrated in FIGS. 1 and 2 deals with the
treatment of the second relatively more volatile overhead vapor
fraction from second distillation column 65. In the embodiment of
FIG. 3, the second relatively more volatile overhead stream is
totally condensed prior to introduction into reflux accumulator
vessel 69. The additional refrigeration duty required to totally
condense the second relatively more volatile overhead stream from
second distillation column 65 is provided by additional indirect
heat exchange means 98 and 99, which are added to high and low
stage ethylene chillers 42 and 54, respectively. Thus, in the
embodiment of FIG. 3, conduit 105 carries the second relatively
more volatile overhead stream from second distillation column 65 to
high-stage ethylene chiller for cooling in indirect heat exchange
means 98. The resulting cooled stream is removed from high-stage
ethylene chiller 44 and transported to reflux condenser 63 via
conduit 106 for cooling in indirect heat exchange means 67. The
cooled stream from indirect heat exchange means 67 of reflux
condenser 63 is transported to low-stage ethylene chiller 54 via
conduit 107 for further cooling and condensing in indirect heat
exchange means 99. The resulting condensed stream is then
transported to reflux accumulator vessel 69 via conduit 108 and the
entire stream is subsequently employed as reflux streams to first
and second distillation columns 60,65.
[0056] FIG. 4 illustrates a third alternative embodiment of the
present invention. The LNG facility shown in FIG. 4 is very similar
to the facilities illustrated in FIGS. 1-3. Therefore, common
components of FIGS. 1-4 are identified with the same reference
numerals, and the written description of these components provided
above with reference to FIGS. 1-3 also applies to FIG. 4. The main
difference between the embodiment illustrated in FIG. 4 and the
embodiments illustrated in FIGS. 1-3 concerns the way that the
compressed and cooled flash gas stream in conduit 155 is processed.
In FIG. 1, the stream in conduit 155 is simply combined with the
first overhead fraction from first distillation column 60 in
conduit 119 and then the combined stream in conduit 120 is
subsequently subjected to further cooling and expansion. In the
embodiment of FIG. 4, the stream in conduit 155 is kept separate
from the first overhead fraction in conduit 119 during cooling in
ethylene chiller 68, cooling in methane economizer 74, and flashing
upstream ofhigh-stage flash drum 80. Thus, the embodiment
illustrated in FIG. 4 includes an additional heat exchange means 11
in ethylene chiller 68, an additional indirect heat exchange means
13 in methane economizer 74, and an additional expansion means 15
upstream of high-stage flash drum 80. It is preferred for ethylene
chiller 68 to be a core-in-kettle heat exchanger, wherein heat
exchange means 75, 70, and 11 are separate cores.
[0057] In the embodiment of FIG. 4, the compressed and cooled flash
gas stream in conduit 155 is cooled in indirect heat exchange means
11 of ethylene chiller 68. The resulting cooled stream is removed
from ethylene chiller 68 in conduit 109 and transported to main
methane economizer 74 for further cooling in indirect heat exchange
means 13. In indirect heat exchange means 13, the stream is cooled
via indirect heat exchange with the flash gas streams in indirect
heat exchange means 82,95,96. The resulting cooled stream exits
methane economizer and is carried to expansion means 15 via conduit
111. In expansion means 15, the condensed stream is flashed, and
the resulting stream is introduced into high-stage flash drum 80
via an inlet that is separate from the inlet for the flashed stream
from expansion means 78. Enhanced efficiency, control, and/or
operability can be provided by keeping the main
predominately-methane stream and the compressed flash gas streams
separate during cooling in ethylene chiller 68 and methane
economizer 74.
[0058] In one embodiment of the present invention, the LNG
production systems illustrated in FIGS. 1-4 are simulated on a
computer using conventional process simulation software. Examples
of suitable simulation software include HYSYS.TM. from Hyprotech,
Aspen Plus.RTM. from Aspen Technology, Inc., and PRO/II.RTM. from
Simulation Sciences Inc.
[0059] The preferred forms of the invention described above are to
be used as illustration only, and should not be used in a limiting
sense to interpret the scope of the present invention. Obvious
modifications to the exemplary embodiments, set forth above, could
be readily made by those skilled in the art without departing from
the spirit of the present invention.
[0060] The inventors hereby state their intent to rely on the
Doctrine of Equivalents to deternine and assess the reasonably fair
scope of the present invention as pertains to any apparatus not
materially departing from but outside the literal scope of the
invention as set forth in the following claims.
* * * * *