U.S. patent application number 11/949118 was filed with the patent office on 2008-08-28 for method for adjusting heating value of lng.
Invention is credited to Robert Burlingame, Joseph H. Cho, Charles Durr, Felix J. Fernandez De La Vega, Heinz Kotzot, JORGE JAVIER VAZQUEZ-ESPARRAGOZA.
Application Number | 20080202161 11/949118 |
Document ID | / |
Family ID | 39492824 |
Filed Date | 2008-08-28 |
United States Patent
Application |
20080202161 |
Kind Code |
A1 |
VAZQUEZ-ESPARRAGOZA; JORGE JAVIER ;
et al. |
August 28, 2008 |
METHOD FOR ADJUSTING HEATING VALUE OF LNG
Abstract
Systems and methods for adjusting the heating value of liquefied
natural gas ("LNG") are provided. LNG can be apportioned into at
least two portions. A first portion can be warmed to provide a
vapor-liquid mixture which can be separated in a first separator to
provide a first vapor and a first liquid. The first liquid can be
separated to provide ANGL and a second vapor. The first vapor can
be compressed and mixed with the second vapor to provide a first
effluent. At least a portion of the first effluent can be used to
heat the first portion. At least a portion of the first effluent
can be used as a first reflux in the first separator. At least a
portion of the first effluent can be mixed with a second portion of
the LNG to provide an adjusted LNG.
Inventors: |
VAZQUEZ-ESPARRAGOZA; JORGE
JAVIER; (Houston, TX) ; Cho; Joseph H.; (Katy,
TX) ; Kotzot; Heinz; (The Woodlands, TX) ;
Fernandez De La Vega; Felix J.; (Houston, TX) ; Durr;
Charles; (Houston, TX) ; Burlingame; Robert;
(Houston, TX) |
Correspondence
Address: |
KELLOGG BROWN & ROOT LLC;ATTN: Christian Heausler
4100 Clinton Drive
HOUSTON
TX
77020
US
|
Family ID: |
39492824 |
Appl. No.: |
11/949118 |
Filed: |
December 3, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60872706 |
Dec 4, 2006 |
|
|
|
Current U.S.
Class: |
62/620 |
Current CPC
Class: |
F25J 2230/08 20130101;
F25J 3/0238 20130101; F17C 2223/0161 20130101; F25J 3/0214
20130101; F17C 2250/0456 20130101; F25J 2235/60 20130101; F25J
2205/04 20130101; F17C 2221/033 20130101; F25J 2200/70 20130101;
F17C 2265/022 20130101; F25J 2230/60 20130101; F25J 2245/02
20130101; F25J 2270/04 20130101; C10L 3/10 20130101; F17C 2223/033
20130101; F25J 2200/04 20130101; F25J 2200/76 20130101; F25J
2220/66 20130101; F25J 3/0233 20130101; F25J 2200/02 20130101; F17C
2265/017 20130101; F25J 2230/20 20130101 |
Class at
Publication: |
62/620 |
International
Class: |
F25J 3/06 20060101
F25J003/06 |
Claims
1) A method for adjusting the heating value and Wobbe index of
liquefied natural gas, comprising: apportioning liquefied natural
gas at a first temperature into at least a first portion and a
second portion; heating the first portion to provide a first
vapor-liquid mixture having a second temperature; selectively
separating, under a first reflux, the first vapor-liquid mixture to
provide a first vapor and a first liquid; compressing at least a
portion of the first vapor comprising methane to provide a
compressed vapor; selectively separating the first liquid to
provide a second vapor comprising methane and a second liquid
comprising NGL; and combining the second vapor and the compressed
vapor to form a first effluent.
2) The method of claim 1, further comprising combining the second
portion of the liquefied natural gas with the first effluent to
provide a first product.
3) The method of claim 2, further comprising vaporizing the first
product.
4) The method of claim 1, wherein the second vapor is expanded and
the first vapor is compressed using a turboexpander.
5) The method of claim 1, wherein at least a portion of the first
effluent is used as a heat transfer fluid to warm the first portion
of the liquefied natural gas.
6) The method of claim 1, wherein the first reflux comprises at
least a portion of the first effluent.
7) The method of claim 1, wherein the first temperature is
-160.degree. C. or lower.
8) The method of claim 1, wherein the second temperature is greater
than -160.degree. C. and less than -88.degree. C.
9) A method for adjusting the heating value of liquefied natural
gas comprising: apportioning the liquefied natural gas at a first
temperature into a first portion and a second portion; heating the
first portion to provide a first intermediate at a second
temperature; heating the first intermediate to provide a first
vapor-liquid mixture at a third temperature; selectively separating
the first vapor-liquid mixture to provide a first vapor and a first
liquid; selectively separating the first liquid to provide a second
vapor and a natural gas liquid product; cooling and selectively
separating the first vapor to provide a third vapor and a second
liquid; compressing the third vapor to provide a compressed vapor;
combining the second vapor and the compressed vapor to provide a
first effluent; and cooling the first effluent.
10) The method of claim 9, further comprising combining the second
liquid and the second portion of the liquefied natural gas to
provide a second effluent.
11) The method of claim 9, further comprising combining the second
effluent with the first effluent to provide a first product.
12) The method of claim 11, further comprising vaporizing the first
product.
13) The method of claim 9, wherein at least a portion of the first
vapor is used as a heat transfer fluid to warm the first portion of
the liquefied natural gas feed.
14) The method of claim 9, wherein at least a portion of the first
effluent is used as a heat transfer fluid to warm the first
intermediate.
15) The method of claim 9, wherein the first temperature is
-160.degree. C. or lower.
16) The method of claim 9, wherein the second temperature is
greater than -160.degree. C. and less than -88.degree. C.
17) The method of claim 9, wherein the third temperature is greater
than -160.degree. C. and less than -88.degree. C.
18) A system for adjusting the heating value and Wobbe Index of
liquefied natural gas, comprising: a heating zone for increasing
the temperature of at least a portion of a liquefied natural gas
above the boiling point of methane and below the boiling point for
C.sub.2 and heavier hydrocarbons; a first separation zone having an
essentially liquid methane first reflux for separating the
vaporized methane from liquid C.sub.2 and heavier hydrocarbons; a
second separation zone for separating residual methane from the
liquid C.sub.2 and heavier hydrocarbons to provide an NGL liquid
product and a methane rich effluent; and a mixing zone for mixing a
bypassed portion of the liquefied natural gas and the methane rich
effluent to provide an adjusted liquefied natural gas product
having a heating value suitable for pipeline transfer.
19) The system of claim 18, wherein the heating zone comprises an
interchanger for exchanging heat between the methane rich first
effluent and the liquefied natural gas.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims benefit of and priority to U.S.
Provisional Application having Ser. No. 60/872,706, filed on Dec.
4, 2006, which is incorporated herein by reference in its
entirety.
BACKGROUND
[0002] 1. Field
[0003] The present embodiments generally relate to systems and
methods for reducing or otherwise adjusting the heating value and
Wobbe Index of a liquefied natural gas ("LNG"). More particularly,
systems and methods for reducing the heating value of liquefied
natural gas ("LNG") and recovery of natural gas liquids ("NGL") are
provided.
[0004] 2. Description of the Related Art
[0005] Liquefied natural gas is rapidly becoming the preferred
means for transporting commercial quantities of natural gas,
especially from stranded deposits to major world markets. However,
depending upon the source of the raw natural gas, LNG can contain
significant quantities of C.sub.2 to C.sub.4 hydrocarbons which
increases the heating value of the natural gas above the maximum of
1,070 BTU/scf and/or maximum Wobbe Index of 1,390 Btu/SCF, which
are typically required for importation and transportation within
the United States and the United Kingdom, among others.
[0006] Several methods are currently employed for reducing the
heating value of a to meet United States and United Kingdom
requirements including: blending with a low heating value LNG;
injecting inert gases into the LNG; and/or removing the heavier
hydrocarbon components (collectively referred to as Natural Gas
Liquids or "NGL") from the LNG. Blending with a low value LNG
requires a substantial investment in both equipment and low heating
value inventory for dilution at the destination port. Dilution with
an inert gas requires a similar substantial investment in both
equipment and inert gas inventory for handling the inert gas at the
destination port. Removal of NGL components from the LNG can also
be capital intensive; however, the cost to remove the NGL may be
offset in markets where the NGL commands a premium over LNG,
thereby providing a potential revenue stream based upon the volume
of recovered NGL.
[0007] A need exists, therefore, for a cost effective system and
method for adjusting a high-heating value LNG by selectively
separating the C.sub.2 and higher NGL to meet pipeline requirements
and provide a fungible NGL product.
BRIEF DESCRIPTION OF THE DRAWINGS
[0008] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0009] FIG. 1 depicts an illustrative system for adjusting the
heating value of LNG according to one or more embodiments
described.
[0010] FIG. 2 depicts another illustrative system for adjusting the
heating value of LNG according to one or more embodiments
described.
[0011] FIG. 3 depicts yet another illustrative system for adjusting
the heating value of LNG according to one or more embodiments
described.
DETAILED DESCRIPTION
[0012] A detailed description will now be provided. Each of the
appended claims defines a separate invention, which for
infringement purposes is recognized as including equivalents to the
various elements or limitations specified in the claims. Depending
on the context, all references below to the "invention" may in some
cases refer to certain specific embodiments only. In other cases it
will be recognized that references to the "invention" will refer to
subject matter recited in one or more, but not necessarily all, of
the claims. Each of the inventions will now be described in greater
detail below, including specific embodiments, versions and
examples, but the inventions are not limited to these embodiments,
versions or examples, which are included to enable a person having
ordinary skill in the art to make and use the inventions, when the
information in this patent is combined with available information
and technology.
[0013] Systems and methods for adjusting the heating value of
liquefied natural gas ("LNG") are provided. LNG can be apportioned
into at least two portions. A first portion can be warmed to
provide a vapor-liquid mixture which can be separated in a first
separator to provide a first vapor and a first liquid. The first
liquid can be separated to provide NGL and a second vapor. The
first vapor can be compressed and mixed with the second vapor to
provide a first effluent. At least a portion of the first effluent
can be used to heat the first portion. At least a portion of the
first effluent can be used as a first reflux in the first
separator. At least a portion of the first effluent can be mixed
with a second portion of the LNG to provide an adjusted LNG.
[0014] As used herein, the terms "Natural Gas Liquids" and/or "NGL"
can refer to those hydrocarbons in natural gas that are separated
as liquids at natural gas processing plants, fractionating and
cycling plants. Natural gas liquids can include, but are not
limited to, ethane; liquefied petroleum gases (propane, butanes,
propane-butane mixtures, ethane-propane mixtures); isopentane;
C.sub.5 and heavier hydrocarbons; and other small quantities of
finished products, such as motor gasoline, special naphthas, jet
fuel, kerosene, and distillate fuel oil.
[0015] With reference to the figures, FIG. 1 depicts an
illustrative system for adjusting the heating value of LNG
according to one or more embodiments. The system 100 can include
one or more heat exchangers 120, two or more separators 140, 190
and one or more compressors 150. In one or more embodiments, at
least a portion of the adjusted LNG can be returned as a first
reflux to the one or more separators 140 to enhance the separation
of LNG and NGL within the separators 140 and 190. The one or more
heat exchangers 120 can be an interchanger, using heat from one or
more intermediate process streams and/or waste streams to preheat
the incoming LNG.
[0016] In one or more embodiments, the incoming LNG via line 105
can be apportioned equally or unequally into a first portion via
line 115 and a second portion via line 110. The apportionment of
the LNG between lines 110 and 115 can be dependent on multiple
factors including, but not limited to, the concentration of
C.sub.2+ components in the LNG, performance and/or efficiency of
the adjustment process, and the desired heating value of the final
product. Based on one or more of these factors, about 0% wt, 20%
wt, about 40% wt, about 60% wt, about 80% wt, about 90% wt, about
95% wt, or about 100% wt of the incoming LNG can flow through the
bypass via line 110, while the balance can be introduced via line
115 to the adjustment system 100. In one or more embodiments, about
0% wt, 5% wt, about 10% wt, about 20% wt, about 40% wt, about 60%
wt, about 80% wt, or about 100% wt of the incoming LNG via line 105
can be introduced to the one or more heaters 120 via line 115,
while the second portion, containing the balance of the LNG, can
flow through the bypass via line 110 for later remixing with an
adjusted LNG effluent.
[0017] In one or more embodiments, the LNG in line 105 can include,
but is not limited to methane, ethane, propane, butane, pentane,
nitrogen, mixtures thereof, or any combination thereof. In one or
more embodiments, the LNG can contain one or more sulfur containing
compounds, for example hydrogen sulfide, H.sub.2S. In one or more
embodiments, the methane content of the LNG can range from about
75% wt to about 99% wt, about 80% wt to about 95% wt, or about 80%
wt to about 90% wt. In one or more embodiments, the ethane content
of the LNG can range from about 1% wt to about 15% wt, about 2% wt
to about 15% wt, or about 3% wt to about 12% wt. In one or more
embodiments, the propane content of the LNG can range from about
0.1% wt to about 10% wt, about 0.1% wt to about 7% wt, or about
0.1% wt to about 5% wt. In one or more embodiments, the butane
content of the LNG can range from about 0.1% wt to about 10.0% wt,
about 0.1% wt to about 6.0% wt, or about 0.1% wt to about 3.0% wt.
In one or more embodiments, the pentane content of the LNG can
range from about 0.01% wt to about 5.0% wt, about 0.01% wt to about
4.0% wt, or about 0.01% wt to about 3.0% wt. In one or more
embodiments, the nitrogen content of the LNG can range from about
0.01% wt to about 10.0% wt, about 0.01% wt to about 0.8% wt, or
about 0.01% wt to about 6.0% wt. In one or more embodiments, the
sulfur content in the LNG can range from about 1 ppmw to about 100
ppmw; from about 1 ppmw to about 75 ppmw; or from about 1 ppmw to
about 50 ppmw.
[0018] In one or more embodiments, the heating value of the LNG in
line 105 can be a minimum of about 1,000 BTU/scf, about 1,150
BTU/scf, about 1,200 BTU/scf, or about 1,250 BTU/scf. In one or
more embodiments, the Wobbe Index of the LNG in line 105 can be a
maximum of about 1,300 BTU/scf, about 1,400 BTU/scf, about 1,500
BTU/scf or about 1,600 BTU/scf. In one or more embodiments, from
about 1% wt to about 90% wt, about 1% wt to about 50% wt, or from
about 1% to about 10% wt of the LNG via line 105 can be vaporized.
In one or more embodiments, the temperature ("first temperature")
of the LNG via line 105 can range from -165.degree. C.
(-265.degree. F.) to about -100.degree. C. (-150.degree. F.), about
-160.degree. C. (-255.degree. F.) to about -125.degree. C.
(-195.degree. F.), or about -150.degree. C. (-240.degree. F.) to
about -100.degree. C. (-150.degree. F.). In one or more
embodiments, the pressure of the LNG via line 105 can range from
100 kPa (0 psig) to about 10,000 kPa (1,435 psig), about 500 kPa
(60 psig) to about 5,000 kPa (710 psig), or about 500 kPa (60 psig)
to about 2,500 kPa (350 psig).
[0019] The first portion via line 115 can be heated using a heat
transfer medium in one or more heaters 120 to at least partially
vaporize the LNG therein and provide a vapor-liquid mixture ("first
mixture") via line 125. In one or more embodiments, the first
mixture in line 125 can contain about 75% wt, about 80% wt, about
85% wt, about 90% wt, about 95% wt, or about 99% wt vapor with the
balance liquid. In one or more embodiments, the vapor in the first
mixture in line 125 can contain about 80 mol % or more, about 90
mol % or more, about 95 mol % or more, or about 99 mol % or more
methane. In one or more embodiments, the liquid in the first
mixture in line 125 can contain about 20 mol % or less, about 10
mol % or less, about 5 mol % or less, or about 1 mol % or less
C.sub.2 and heavier hydrocarbons.
[0020] Maintaining the exit temperature ("second temperature") of
the one or more heaters 120 at a temperature above the boiling
point of methane, but below the boiling point of C.sub.2 and
heavier hydrocarbons can promote the formation of a vapor-liquid
mixture in line 125 having a vapor phase rich in methane and a
liquid phase rich in NGLs. For example, the second temperature can
range from about -160.degree. C. (-255.degree. F.) to about
-50.degree. C. (-60.degree. F.), about -160.degree. C.(-255.degree.
F.) to about -75.degree. C. (-105.degree. F.), or about
-160.degree. C. (-255.degree. F.) to about -100.degree. C.
(-150.degree. F.).
[0021] In one or more embodiments, the one or more heat exchangers
120 can include, but are not limited to shell and tube, U-tube,
bayonet, regenerative, plate and frame, or any combination thereof
in series or parallel. In one or more embodiments, the one or more
heat exchangers 120 can include a directed fired heater. In one or
more embodiments, the operating pressure of the heat exchanger 120
can range from 100 kPa (0 psig) to about 10,000 kPa (1,435 psig),
about 500 kPa (60 psig) to about 5,000 kPa (710 psig), or about 500
kPa (60 psig) to about 2,500 kPa (350 psig).
[0022] The first mixture in line 125 can be introduced to the one
or more separators ("first separator") 140 to provide a vapor
("first vapor") via line 145 and a liquid ("first liquid") via line
160. In one or more embodiments, a first reflux (discussed in
greater detail below) can be circulated via line 175 through the
first separator 140 to cool the vapor in the first separator 140,
condensing any residual C.sub.2 and heavier hydrocarbons present,
thereby minimizing the concentration of C.sub.2 and heavier
hydrocarbons within the first vapor in line 145.
[0023] In one or more embodiments, the first vapor in line 145 can
contain about 80 mol % or more; about 85 mol % or more; about 90
mol % or more; about 95 mol % or more; about 99 mol % or more
methane. In one or more embodiments, the first vapor via line 145
can contain about 1 mol % or less; about 5 mol % or less; about 10
mol % or less; about 15 mol % or less; about 20 mol % or less
nitrogen and/or other non-condensables, for example hydrogen. The
first vapor in line 145 can be compressed using one or more
compressors 150 to provide a compressed first vapor via line 155.
The compressor 150 can include any device suitable for compressing
a gas, and/or multi-phase fluid, for example one or more
reciprocating, rotary, axial flow, centrifugal, diagonal or
mixed-flow, scroll, or diaphragm compressors or any series and/or
parallel combination thereof. The compressor 150 can have one or
more compressor stages with or without intercooling between
successive stages. In one or more embodiments, the pressure of the
compressed vapor in line 155 can range from about 200 kPa (15 psig)
to about 20,000 kPa (2,890 psig), about 1,000 kPa (130 psig) to
about 10,000 kPa (1,435 psig), or about 1,000 kPa (130 psig) to
about 5,000 kPa (710 psig). In one or more embodiments, the
temperature of the compressed vapor in line 155 can range from
about -100.degree. C. (-150.degree. F.) to about 100.degree. C.
(210.degree. F.), about -100.degree. C. (-150.degree. F.) to about
50.degree. C. (120.degree. F.), or about -50.degree. C.
(-60.degree. F.) to about 50.degree. C. (120.degree. F.).
[0024] In one or more embodiments, the first liquid via line 160
can contain about 60% wt or more; about 70% wt or more; about 80%
wt or more; about 85% wt or more; about 90% wt or more; or about
95% wt or more C.sub.2 and heavier hydrocarbons. In one or more
embodiments, the temperature of the first liquid in line 160 can
range from about -160.degree. C. (-255.degree. F.) to about
-90.degree. C. (-130.degree. F.), about -160.degree. C.
(-255.degree. F.) to about -100.degree. C. (-150.degree. F.), or
about -160.degree. C. (-255.degree. F.) to about -125.degree. C.
(-190.degree. F.). The pressure of the first liquid in line 160 can
range from about 200 kPa (15 psig) to about 20,000 kPa (2,890
psig), about 1,000 kPa (130 psig) to about 10,000 kPa (1,430 psig),
or about 1,000 kPa (130 psig) to about 5,000 kPa (710 psig).
[0025] The one or more first separators 140 can be a vessel having
internal packing media, such as rings, saddles, balls, irregular
sheets, tubes, spirals, trays, plates, and/or baffles, to
facilitate the separation of liquids and vapors therein. In one or
more embodiments, the operating temperature in the first separator
140 can range from -165.degree. C. (-265.degree. F.) to about
-100.degree. C. (-150.degree. F.), about -160.degree. C.
(-255.degree. F.) to about -125.degree. C. (-190.degree. F.), or
about -150.degree. C. (-240.degree. F.) to about -100.degree. C.
(-150.degree. F.). In one or more embodiments, the operating
pressure in the first separator 140 can range from 100 kPa (0 psig)
to about 10,000 kPa (1,435 psig), about 500 kPa (60 psig) to about
5,000 kPa (710 psig), or about 500 kPa (60 psig) to about 2,500 kPa
(350 psig).
[0026] The first liquid, exiting the first separator 140 via line
160, can be transferred to the separator ("second separator") 190
via one or more transfer devices 143. In one or more embodiments,
the transfer device 143 can be a pump or compressor. In one or more
embodiments, the transfer device 143 can increase the pressure of
the first liquid in line 160 about 690 kPa (100 psi); about 515 kPa
(75 psi); or about 350 kPa (50 psi). Upon introduction to the one
or more second separators 190, the first liquid can flash into a
liquid ("second liquid") phase and a vapor ("second vapor") phase.
The second vapor, containing essentially methane, can be withdrawn
from the second separator 190 via line 170. The second liquid,
containing one or more liquefied C.sub.2 and heavier hydrocarbons
(i.e. NGL), can be withdrawn via line 165. In one or more
embodiments, the second vapor in line 170 can contain about 80 mol
% or more; about 85 mol % or more; about 90 mol % or more; about 95
mol % or more; or about 99 mol % or more methane. In one or more
embodiments, the second vapor via line 170 can contain about 20 mol
% or less; about 15 mol % or less; about 10 mol % or less; about 5
mol % or less; or about 1 mol % or less; nitrogen and/or other
non-condensables, for example hydrogen. In one or more embodiments,
the temperature of the second vapor in line 170 can range from
about -100.degree. C. (-150.degree. F.) to about 100.degree. C.
(210.degree. F.), about -100.degree. C. (-150.degree. F.) to about
50.degree. C. (120.degree. F.), or about -50.degree. C.
(-60.degree. F.) to about 50.degree. C. (120.degree. F.). In one or
more embodiments, the pressure of the second vapor in line 170 can
range from about 200 kPa (15 psig) to about 20,000 kPa (2,890
psig), about 1,000 kPa (130 psig) to about 10,000 kPa (1,435 psig),
or about 1,000 kPa (130 psig) to about 5,000 kPa (710 psig).
[0027] In one or more embodiments, at least a portion of the second
liquid in line 165 can be removed via line 167, heated using one or
more heat exchangers 195, and returned to the second separator 190
as a second reflux. In one or more embodiments, the temperature of
the second liquid in line 167 exiting the one or more heat
exchangers 195 can range from about -160.degree. C. (-255.degree.
F.) to about -90.degree. C. (-130.degree. F.), about -160.degree.
C. (-255.degree. F.) to about -100.degree. C. (-150.degree. F.), or
about -160.degree. C. (-255.degree. F.) to about -125.degree. C.
(-190.degree. F.). In one or more specific embodiments, the second
separator 190 can be operated in the two phase region, at a
temperature less than the critical temperature of the second
liquid. As the operating pressure of the second separator 190 is
reduced, the required heat input to the reboiler 195 can be
commensurately reduced as well.
[0028] In one or more embodiments, the second liquid in line 165
can contain about 60% wt or more; about 70% wt or more; about 80%
wt or more; about 90% wt or more; about 95% wt or more; or about
99% wt or more C.sub.2 and heavier hydrocarbons. In one or more
embodiments, the ethane concentration in the second liquid in line
165 can range from about 40% wt to about 99% wt, about 60% wt to
about 99% wt, or about 80% wt to about 99% wt. In one or more
embodiments, the propane concentration in the second liquid in line
165 can range from about 1% wt to about 60% wt, about 1% wt to
about 40% wt, or about 1% wt to about 20% wt. In one or more
embodiments, the butane concentration in the second liquid in line
165 can range from about 1% wt to about 60% wt, about 1% wt to
about 40% wt, or about 1% wt to about 20% wt. In one or more
embodiments, the pentane concentration in the second liquid in line
165 can range from about 1% wt to about 60% wt, about 1% wt to
about 40% wt, or about 1% wt to about 20% wt.
[0029] Any sulfur compounds present in the LNG in line 105 can
concentrate in the second liquid in line 165. Sulfur compounds
present in LNG can include, but are not limited to, hydrogen
sulfide, carbonyl sulfide, methyl mercaptan, ethyl mercaptan, and
n-propyl mercaptan. In one or more embodiments, the sulfur content
of the second liquid in line 165 can range from about 1 ppmw to
about 500 ppmw; from about 1 ppmw to about 400 ppmw; or from about
1 ppmw to about 300 ppmw. Where the second liquid in line 165 is
used as a fuel supply, sulfur dioxide ("SO.sub.2") emissions should
be included in the air emissions and suitable SO.sub.2 corrosion
resistance measures can be incorporated into the process
design.
[0030] Sulfur compounds present in the second liquid can be removed
prior to marketing the second liquid as an NGL. While several
options exist to remove sulfur containing compounds, the ultimate
selection of a sulfur removal process can be influenced by the
imported LNG specifications and the NGL market specifications. The
selection of a sulfur removal process can be influenced by the
effectiveness of the process in removing various sulfur containing
compounds, since some processes are effective at reducing mercaptan
levels, but not hydrogen sulfide and carbonyl sulfide levels. The
overall cost of desulfurization, including waste removal, disposal
and associated costs can be evaluated and considered in the
selection process.
[0031] The one or more second separators 190 can be any system,
device or combination of systems and/or devices capable of
separating a multiphase mixture into a relatively liquid-free
second vapor via line 170 and a relatively vapor-free second liquid
via line 165. The second separator 190 can include internal packing
media, such as rings, saddles, balls, irregular sheets, tubes,
spirals, trays, plates, and/or baffles, to facilitate the
liquid/vapor separation. In one or more embodiments, the operating
temperature of the second separator 190 can range from about
-100.degree. C. (-150.degree. F.) to about 100.degree. C.
(210.degree. F.), about -100.degree. C. (-150.degree. F.) to about
50.degree. C. (120.degree. F.), or about -50.degree. C.
(-60.degree. F.) to about 50.degree. C. (120.degree. F.). In one or
more embodiments, the operating pressure of the second separator
190 can range from 200 kPa (15 psig) to about 20,000 kPa (2,890
psig), about 1,000 kPa (130 psig) to about 10,000 kPa (1,430 psig),
or about 1,000 kPa (130 psig) to about 5,000 kPa (710 psig).
[0032] The one or more heat exchangers 195 can include, but are not
limited to a shell and tube, U-tube, bayonet, regenerative, plate
and frame, or any combination thereof in series or parallel. In one
or more embodiments, a non-freezing heat transfer fluid can be used
to supply heat to the heat exchangers 195 due to the potential for
low operating temperatures within the reboiler. In one or more
embodiments, the one or more heat exchangers 195 can be an
interchanger or regenerative heat exchanger using process or waste
heat, for example heat provided by the exhaust from a combustion
process, to increase the temperature of the second liquid in line
167. In one or more embodiments, the one or more heat exchangers
195 can include a directed fired heater. In one or more
embodiments, the operating temperature of the one or more heat
exchangers 195 can range from -165.degree. C. (-265.degree. F.) to
about -100.degree. C. (-150.degree. F.), about -160.degree. C.
(-255.degree. F.) to about -125.degree. C. (-190.degree. F.), or
about -150.degree. C. (-240.degree. F.) to about -100.degree. C.
(-150.degree. F.). In one or more embodiments, the operating
pressure of the one or more heat exchangers 195 can range from 100
kPa (0 psig) to about 10,000 kPa (1,435 psig), about 500 kPa (60
psig) to about 5,000 kPa (710 psig), or about 500 kPa (60 psig) to
about 2,500 kPa (350 psig).
[0033] Referring back to the one or more compressors 150, at least
a portion of the compressed first vapor exiting the compressor 150
via line 155 can be combined with at least a portion of the second
vapor exiting the separator 190 via line 170 to form a first
effluent in line 180. In one or more embodiments, all or a portion
of the first effluent via line 180 can be used as the heat transfer
medium in the one or more heat exchangers 120, supplying the heat
necessary to warm the first portion of the LNG in line 115. In one
or more embodiments, the contact with the first portion of the LNG
in line 115 can condense and sub-cool at least a portion of the
first effluent. In one or more embodiments, about 5% wt, about 20%
wt, about 40% wt, about 60% wt, about 80% wt, about 90% wt, or
about 95% wt of the first effluent via line 180 can condense in the
one or more heat exchangers 120.
[0034] In one or more embodiments, the partially condensed first
effluent can exit the one or more heat exchangers 120 via line 182.
In one or more embodiments, the first effluent in line 182 can
contain a minimum of about 80 mol % or more; about 85 mol % or
more; about 90 mol % or more; about 95 mol % or more; or about 99
mol % or more methane. In one or more embodiments, the first
effluent via line 182 can contain about 20 mol % or less; about 15
mol % or less; about 10 mol % or less; about 5 mol % or less; or
about 1 mol % or less; nitrogen and/or other non-condensables, for
example hydrogen. In one or more embodiments, the temperature of
the first effluent in line 182 can range from about -100.degree. C.
(-150.degree. F.) to about 100.degree. C. (210.degree. F.), about
-100.degree. C. (-150.degree. F.) to about 50.degree. C.
(120.degree. F.), or about -50.degree. C. (-60.degree. F.) to about
50.degree. C. (120.degree. F.). In one or more embodiments, the
pressure of the first effluent in line 182 can range from about 200
kPa (15 psig) to about 20,000 kPa (2,890 psig), about 1,000 kPa
(130 psig) to about 10,000 kPa (1,435 psig), or about 1,000 kPa
(130 psig) to about 5,000 kPa (710 psig).
[0035] In one or more embodiments, at least a portion of the first
effluent in line 182 can be used to provide the first reflux via
line 175 to the one or more first separators 140. In one or more
embodiments, the first reflux via line 175 can enhance the
separation of methane and NGL liquids within the first separator
140. The reflux ratio (first mixture-to-finished product reflux) of
the first reflux can range from about 200:1 to about 5:1; about
150:1 to about 10:1; or, more preferably from about 100:1 to about
20:1. In one or more specific embodiments, sharp increases in NGL
recovery rates can occur at first reflux rates up to approximately
100:1 (i.e. up to a 1% recycle) with lesser increases occurring at
reflux rates greater than 100:1 (i.e. greater than 1% recycle).
[0036] In one or more embodiments, at least a portion of the first
effluent via line 182 can be combined with the second portion of
the LNG via line 110 to form a first product via line 185
containing natural gas having a heating value suitable for pipeline
transfer. In one or more embodiments, the first product can contain
about 80 mol % or more; about 85 mol % or more; about 90 mol % or
more; about 95 mol % or more; or about 99 mol % or more methane. In
one or more embodiments, the ethane content of the first product in
line 185 can range from about 0.1% wt to about 5% wt, about 0.1% wt
to about 4% wt, or about 0.1% wt to about 3% wt. In one or more
embodiments, the propane content of the first product can range
from about 0.05% wt to about 2% wt, about 0.10% wt to about 1% wt,
or about 0.10% wt to about 0.75% wt. In one or more embodiments,
the butane content of the first product can range from about 0.01%
wt to about 0.3% wt, about 0.01% wt to about 0.2% wt, or about
0.01% wt to about 0.01% wt. In one or more embodiments, the pentane
content of the first product can range from about 0.001% wt to
about 0.01% wt, about 0.001% wt to about 0.008% wt, or about 0.001%
wt to about 0.005% wt. In one or more embodiments, the nitrogen
content of the first product can range from about 0.1% wt to about
5% wt, about 0.5% wt to about 3% wt, or about 0.5% wt to about 2%
wt.
[0037] In one or more embodiments, the heating value of the first
product in line 185 can be a maximum of about 1,100 BTU/scf, about
1,050 BTU/scf, or about 1,000 BTU/scf. In one or more embodiments,
the Wobbe Index of the first product in line 185 can be a maximum
of about 1,390 BTU/scf, about 1,350 BTU/scf, or about 1,310
BTU/scf. In one or more embodiments, from about 1% wt to about 90%
wt, about 1% wt to about 50% wt, or from about 1% to about 10% wt
of the first product via line 185 can be vaporized. In one or more
embodiments, the temperature of the first product via line 185 can
range from -150.degree. C. (-240.degree. F.) to about 50.degree. C.
(120.degree. F.), about -100.degree. C. (-150.degree. F.) to about
25.degree.0 C. (80.degree. F.), or about -50.degree. C.
(-60.degree. F.) to about -25.degree. C. (-10.degree. F.). In one
or more embodiments, the pressure of the first product via line 185
can range from 100 kPa (0 psig) to about 10,000 kPa (1,435 psig),
about 500 kPa (60 psig) to about 5,000 kPa (710 psig), or about 500
kPa (60 psig) to about 2,500 kPa (350 psig).
[0038] FIG. 2 depicts another illustrative system 200 for adjusting
the heating value of LNG according to one or more embodiments. In
addition to the one or more heat exchangers 120, and separators
140, 190, discussed above with reference to FIG. 1, the system 200
can include one or more turboexpander/compressors 220. In one or
more embodiments, the second vapor in line 170 can be introduced to
an expander portion of the one or more turboexpander/compressor 220
to provide a third vapor via line 215. The shaft power generated by
the expander portion of the turboexpander/compressor can be used to
compress the first vapor in line 145 to provide the compressed
first vapor in line 155. In one or more embodiments, at least a
portion of the compressed first vapor in line 155 can be combined
with at least a portion of the third vapor via line 215 to provide
the first effluent via line 180. The system 200, as depicted in
FIG. 2, can process LNG having a high concentration of C.sub.2 and
heavier hydrocarbons without experiencing a significant change in
operating conditions. As depicted in FIG. 2, the first reflux to
the first separator 140 can provide flexibility in increasing NGL
production when compared to systems where no first reflux
occurs.
[0039] The turboexpander/compressor 220 can control the process
pressure in the first effluent in line 180, permitting a lower
pressure in the feed and reduced condensing of the LNG product in
the one or more heat exchangers 120. In one or more embodiments,
the temperature of the third vapor in line 215 can range from
-150.degree. C. (-240.degree. F.) to about 50.degree. C.
(120.degree. F.), about -100.degree. C. (-150.degree. F.) to about
25.degree. C. (80.degree. F.), or about -50.degree. C. (-60.degree.
F.) to about -25.degree. C. (-10.degree. F.). In one or more
embodiments, the pressure of the third vapor in line 215 can range
from 100 kPa (0 psig) atm to about 10,000 kPa (1,435 psig), about
500 kPa (60 psig) to about 5,000 kPa (710 psig), or about 500 kPa
(60 psig) to about 2,500 kPa (350 psig).
[0040] In one or more embodiments, the turboexpander/compressor 220
can include a turbine and a centrifugal compressor, with the
turbine and the compressor impeller sharing a common shaft. The
compressor side of the turboexpander/compressor 220 can be used to
compress the first vapor in line 145. The energy needed to drive
the turboexpander/compressor 220 can be derived by passing the
second vapor in line 170 through the turbine portion of the
turboexpander/compressor 220. Since work can be extracted from the
second vapor as it spins the turbine, the pressure and temperature
of the third vapor via line 215 exiting the turbine can be lower
than the pressure and temperature of the second vapor in line 170
entering the turbine. Although not shown in FIG. 2, the
turboexpander/compressor 220 can be equipped with an electric
driver to enable the compression of the first vapor in line 145
should the expander section be taken offline.
[0041] In systems 100 and 200, as depicted in FIGS. 1 and 2, the
first reflux via line 175 can return at least a portion of the
first effluent in line 182 to the first separator 140. Increasing
the first reflux rate via line 175 can proportionately increase the
C.sub.2 recovery rate in the first liquid in line 160, thereby
decreasing the heating value of the first effluent in line 180. Due
to the reduced heating value of the first effluent in line 180, the
portion of LNG bypassing the adjustment process via line 110 can be
increased, thereby reducing the size of the required LNG adjustment
system.
[0042] FIG. 3 depicts yet another illustrative system 300 for
adjusting the heating value of LNG according to one or more
embodiments. In one or more embodiments, the LNG in line 105 can be
apportioned into equal or unequal portions, with a first portion in
line 115 and a second portion in line 110. The first portion in
line 115 can be directed through a heat exchanger 320 wherein the
first portion can be warmed using a heat transfer fluid. In one or
more embodiments, the first vapor in line 145 can be used as the
heat transfer fluid to provide a warmed feed via line 325 and a
cooled first vapor, at least a portion of which can be condensed,
via line 330. In one or more embodiments, the cooled first vapor in
line 330 can be introduced to one or more third separators 340
where a liquid can be removed via line 335, and a vapor removed via
line 345. The vapor in line 345 can be compressed using the one or
more compressors 150 to provide the compressed first vapor via line
155. In one or more embodiments, at least a portion of the liquid
in line 335 can be combined with the second portion of the feed via
line 110 to form a mixture in line 375 which, when combined with
the first effluent via line 180, can provide the first product via
line 185.
[0043] In one or more embodiments, the vapor content in the warmed
feed in line 325 can be about 50% wt or more; about 60% wt or more;
about 70% wt or more; about 80% wt or more; about 90% wt or more;
about 95% wt or more; or about 99% wt or more, with the balance
liquid. In one or more embodiments, the vapor present in the warmed
feed of line 325 can contain a minimum of about 80 mol % or more;
about 90 mol % or more; about 95 mol % or more; about 99 mol % or
more; about 99.9 mol % or more methane. In one or more embodiments,
the liquid present in the warmed feed of line 325 can contain about
60% wt or more; about 70% wt or more; about 80% wt or more; about
90% wt or more; about 95% wt or more; or about 99% wt or more
C.sub.2 and heavier hydrocarbons. In one or more embodiments, the
temperature of the warmed feed of line 325 can range from about
-160.degree. C. (-255.degree. F.) to about -90.degree. C.
(-130.degree. F.), about -160.degree. C. (-255.degree. C.) to about
-100.degree. C. (-150.degree. F.), or about -160.degree. C.
(-255.degree. F.) to about -125.degree. C. (-190.degree. F.).
[0044] In one or more embodiments, the vapor content in the cooled
first vapor exiting the pre-heater 320 via line 330 can contain
about 50% wt or more; about 60% wt or more; about 70% wt or more;
about 80% wt or more; about 90% wt or more; about 95% wt or more;
or about 99% wt or more, with the balance liquid. In one or more
embodiments, the cooled first vapor via line 330 can contain about
80 mol % or more; about 90 mol % or more; about 95 mol % or more;
or about 99 mol % or more methane. In one or more embodiments, the
cooled first vapor via line 330 can contain a maximum of about 20
mol % or less; about 10 mol % or less; about 5 mol % or less; or
about 1 mol % or less nitrogen and/or other non-condensables, for
example hydrogen. In one or more embodiments, the temperature of
the cooled first vapor in line 330 can range from about
-160.degree. C. (-255.degree. F.) to about -90.degree. C.
(-130.degree. F.), about -160.degree. C. (-255.degree. C.) to about
-100.degree. C.(-150.degree. F.), or about -160.degree. C.
(-255.degree. F.) to about -125.degree. C. (-190.degree. F.).
[0045] In one or more embodiments, the liquid content in the
condensed liquid in line 335 can be about 50% wt or more; about 60%
wt or more; about 70% wt or more; about 80% wt or more; about 90%
wt or more; about 95% wt or more; or about 99% wt or more, with the
balance vapor. In one or more embodiments, the condensed liquid in
line 335 can contain about 20 mol % or less; about 10 mol % or
less; about 5 mol % or less; or about 1 mol % or less methane. In
one or more embodiments, the condensed liquid in line 335 can
contain about 20 mol % or less; about 10 mol % or less; about 5 mol
% or less; about 1 mol % or less nitrogen and/or other
non-condensables such as hydrogen. In one or more embodiments, the
temperature of the condensed liquid in line 335 exiting the one or
more second separators 340 can range from about -160.degree. C.
(-255.degree. F.) to about -90.degree. C. (-130.degree. F.), about
-160.degree. C. (-255.degree. C.) to about -100.degree. C.
(-150.degree. F.), or about -160.degree. C. (-255.degree. F.) to
about -125.degree. C. (-190.degree. F.).
[0046] In one or more embodiments, the vapor content in the vapor
in line 345 can be about 90 wt % or more; about 95 wt % or more;
about 99 wt % or more; or about 99.9 wt % or more. In one or more
embodiments, the vapor in line 345 can contain about 80 mol % or
more; about 90 mol % or more; about 95 mol % or more; or about 99
mol % or more methane. In one or more embodiments, the vapor in
line 345 can contain about 20 mol % or less; about 10 mol % or
less; about 5 mol % or less; or about 1 mol % or less; nitrogen
and/or other non-condensables such as hydrogen. In one or more
embodiments, the temperature of vapor in line 345 can range from
about -160.degree. C. (-255.degree. F.) to about -90.degree. C.
(-130.degree. F.), about -160.degree. C. (-255.degree. C.) to about
-100.degree. C. (-150.degree. F.), or about -160.degree. C.
(-255.degree. F.) to about -125.degree. C. (-190.degree. F.).
[0047] In one or more embodiments, at least a portion of the
condensed liquid in line 335 can be combined with the second
portion of the LNG via line 110, forming a mixture in line 375. In
one or more embodiments, the mixture in line 375 can contain about
80 mol % or more; about 90 mol % or more; about 95 mol % or more;
or about 99 mol % or more methane. In one or more embodiments, the
mixture in line 375 can contain about 20 mol % or less; about 10
mol % or less; about 5 mol % or less; or about 1 mol % or less;
nitrogen and/or other non-condensables such as hydrogen. In one or
more embodiments, the temperature in line 375 can range from about
-165.degree. C. (-265.degree. F.) to about 0.degree. C. (30.degree.
F.), about -165.degree. C. (-265.degree. F.) to about -125.degree.
C. (-190.degree. F.), or about -165.degree. C. (-265.degree. F.) to
about -140.degree. C. (-220.degree. F.). In one or more
embodiments, the pressure in line 375 can range from about 200 kPa
(15 psig) to about 20,000 kPa (2,885 psig), about 1,000 kPa (130
psig) to about 10,000 kPa (1,435 psig), or about 1,000 kPa (130
psig) to about 5,000 kPa (710 psig).
[0048] In one or more embodiments, the one or more heat exchangers
320 can be any system, device or combination of systems and/or
devices capable of increasing the temperature of the incoming first
portion of LNG via line 115. The one or more heat exchangers 320
can include, but are not limited to, one or more of the following:
shell-and-tube, U-tube, bayonet, plate and frame heat exchangers or
any combination thereof, arranged either in series, parallel, or
any combination thereof. The heat exchanger 320 can include one or
more direct fired heaters, combusting a liquid or gas fuel to
increase the temperature of the first portion of the incoming LNG
in line 115. The heat exchanger 320 can be one or more
interchangers or other regenerative type heat exchangers using
process and/or waste heat to increase the temperature of the first
portion of the LNG in line 115. In one or more embodiments, the
operating temperature of the heat exchanger 320 can range from
-165.degree. C. (-265.degree. F.) to about -100.degree. C.
(-150.degree. F.), about -160.degree. C. (-255.degree. F.) to about
-125.degree. C. (-190.degree. F.), or about -150.degree. C.
(-240.degree. F.) to about -100.degree. C. (-150.degree. F.). In
one or more embodiments, the operating pressure of the heat
exchangers 320 can range from 100 kPa (0 psig) to about 10,000 kPa
(1,435 psig), about 500 kPa (60 psig) to about 5,000 kPa (710
psig), or about 500 kPa (60 psig) to about 2,500 kPa (350
psig).
[0049] The one or more third separators 340 can be any system,
device or combination of systems and/or devices capable of
separating a mixture containing vapor and liquid into a vapor
overhead and a liquid bottoms. The third separator 340 can include
internal packing media, such as rings, saddles, balls, irregular
sheets, tubes, spirals, trays, plates, and/or baffles, to
facilitate the liquid/vapor separation. In one or more embodiments,
the operating temperature within the third separator 340 can range
from -165.degree. C. (-265.degree. F.) to about -100.degree. C.
(-150.degree. F.), about -160.degree. C. (-255.degree. F.) to about
-125.degree. C. (-190.degree. F.), or about -150.degree. C.
(-240.degree. F.) to about -100.degree. C. (-150.degree. F.). In
one or more embodiments, the operating pressure within the third
separator 340 can range from 100 kPa (0 psig) to about 10,000 kPa
(1,435 psig), about 500 kPa (60 psig) to about 5,000 kPa (710
psig), or about 500 kPa (60 psig) to about 2,500 kPa (350
psig).
[0050] The system 300, as depicted in FIG. 3, makes use of two heat
exchangers, 120 and 320, to at least partially recondense the
overhead vapor from the separators, 140 and 190, and to further
pressurize the LNG feeding into the separators 140 and 190. The use
of two heat exchangers, 120 and 320 in the system depicted in FIG.
3 decreases the duty on the individual heat exchangers 120 and 320,
thereby promoting stability in operation of the system 300. The use
of two heat exchangers, 120 and 320 can reduce the power required
to drive the one or more compressors 150 by decreasing the volume
of vapor introduced to the compressor via line 345.
[0051] NGL extraction volume is strongly affected by C.sub.2
recovery rate which, in systems 100 and 200, can be controlled via
the first reflux of at least a portion of LNG product to the first
separator 140, via line 175. Where the first reflux to the first
separator 140 is not possible, for example in the system 300,
depicted in FIG. 3, less flexibility exists for controlling the NGL
recovery rate.
[0052] Certain embodiments and features have been described using a
set of numerical upper limits and a set of numerical lower limits.
It should be appreciated that ranges from any lower limit to any
upper limit are contemplated unless otherwise indicated. Certain
lower limits, upper limits and ranges appear in one or more claims
below. All numerical values are "about" or "approximately" the
indicated value, and take into account experimental error and
variations that would be expected by a person having ordinary skill
in the art.
[0053] Various terms have been defined above. To the extent a term
used in a claim is not defined above, it should be given the
broadest definition persons in the pertinent art have given that
term as reflected in at least one printed publication or issued
patent. Furthermore, all patents, test procedures, and other
documents cited in this application are fully incorporated by
reference to the extent such disclosure is not inconsistent with
this application and for all jurisdictions in which such
incorporation is permitted.
[0054] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *