U.S. patent application number 11/614694 was filed with the patent office on 2008-06-26 for process and apparatus for reducing the heating value of liquefied natural gas.
This patent application is currently assigned to Chevron U.S.A. Inc.. Invention is credited to Sunil Dutt, Piers Hodges, Carlos M. Yengle.
Application Number | 20080148771 11/614694 |
Document ID | / |
Family ID | 39540958 |
Filed Date | 2008-06-26 |
United States Patent
Application |
20080148771 |
Kind Code |
A1 |
Yengle; Carlos M. ; et
al. |
June 26, 2008 |
PROCESS AND APPARATUS FOR REDUCING THE HEATING VALUE OF LIQUEFIED
NATURAL GAS
Abstract
A process and apparatus is provided for reducing the heating
value of imported LNG by removing natural gas liquid products while
condensing boil-off gas. The LNG is pumped from a storage container
and is then heated by cross exchange to a dew point temperature. A
portion of this heated LNG is sent out to be vaporized while the
remaining portion is further heated by cross exchange with
demethanizer overhead vapors and is then sent as feed to the
demethanizer. NGL is recovered at the bottom of the demethanizer,
and the overhead vapors are mixed with boil off gas coming from the
LNG storage container. These mixed vapors are condensed by cross
exchanging with the LNG feed portion and then pumped to pipeline
pressure and sent to the gas pipeline through the vaporizers.
Inventors: |
Yengle; Carlos M.; (Houston,
TX) ; Dutt; Sunil; (Katy, TX) ; Hodges;
Piers; (London, GB) |
Correspondence
Address: |
CHEVRON CORPORATION
P.O. BOX 6006
SAN RAMON
CA
94583-0806
US
|
Assignee: |
Chevron U.S.A. Inc.
|
Family ID: |
39540958 |
Appl. No.: |
11/614694 |
Filed: |
December 21, 2006 |
Current U.S.
Class: |
62/613 ;
62/616 |
Current CPC
Class: |
F17C 2265/037 20130101;
F17C 2227/0388 20130101; F17C 2270/0123 20130101; F17C 2270/0136
20130101; F25J 3/0238 20130101; F25J 2245/90 20130101; F17C
2265/017 20130101; F25J 2200/70 20130101; F25J 2235/60 20130101;
F17C 2265/03 20130101; F17C 2221/033 20130101; F17C 2223/033
20130101; F17C 2227/039 20130101; F17C 2223/046 20130101; F17C
2227/0157 20130101; F17C 2223/0161 20130101; F17C 2265/033
20130101; F17C 13/004 20130101; F17C 2227/0306 20130101; F17C
2270/0171 20130101; F25J 2290/62 20130101; F17C 2227/0135 20130101;
F17C 2265/034 20130101; F25J 3/0233 20130101; F25J 2200/02
20130101; F17C 2227/0309 20130101; F25J 3/0214 20130101; F17C
2225/0123 20130101; F17C 2270/0173 20130101; F17C 2225/035
20130101; F17C 2270/0105 20130101; F17C 2250/0456 20130101 |
Class at
Publication: |
62/613 ;
62/616 |
International
Class: |
F25J 3/00 20060101
F25J003/00 |
Claims
1) A process for reducing the heating value of LNG, comprising:
splitting an LNG stream into a separations feed stream and a
vaporization feed stream; cross heat-exchanging the separations
feed stream with a combined boil-off gas and overheads stream;
separating the separations feed stream into the overheads stream
and a bottoms stream; and combining the combined boil-off gas and
overheads stream with the vaporization feed stream.
2. The process according to claim 1, wherein a flowrate ratio
between the separations feed stream and the vaporization stream is
in the range of about 20:80 to about 40:60.
3) The process according to claim 1, wherein the LNG stream
pressure is in the range of about 75 to about 125 psig.
4) The process according to claim 1, wherein the LNG stream is at a
dew point temperature.
5) The process according to claim 1, wherein the separations feed
stream is separated into the overheads stream and the bottoms
stream in a demethanizer.
6) The process according to claim 1, wherein the combined boil-off
gas and overheads stream is formed by combining a boil-off gas
stream with the separations feed stream before the separations feed
stream is separated into the overheads stream and the bottoms
stream.
7) The process according to claim 1, wherein the combined boil-off
gas and overheads stream is formed by combining a boil-off gas
stream with the overheads stream after the separations feed stream
is separated into the overheads stream and the bottoms stream.
8) The process according to claim 1, wherein the overheads stream
comprises at least about 98 mol % methane.
9) The process according to claim 1, wherein the cross
heat-exchanging of the separations feed stream with the combined
boil-off gas and overheads stream condenses at least a portion of
the combined boil-off gas and overheads stream.
10) An apparatus for reducing the heating value of LNG, comprising:
a pump for pumping an LNG stream; a flow control device for
splitting the LNG stream into a separations feed stream and a
vaporization stream; at least one heat exchanger for cross
heat-exchanging the separations feed stream with a combined
boil-off gas and overheads stream; and a separations column for
separating the separations feed stream into the overheads stream
and a bottoms stream.
11) The apparatus according to claim 10, wherein the flow control
device controls a flowrate ratio between the separations feed
stream and the vaporization stream within the range of about 20:80
to about 40:60.
12) The apparatus according to claim 10, wherein the pump maintains
the LNG stream at a pressure in the range of about 75 to about 125
psig.
13) The apparatus according to claim 10, wherein the LNG stream is
at a dew point temperature.
14) The apparatus according to claim 10, wherein the separations
column is a demethanizer.
15) The apparatus according to claim 10, further comprising a
manifold disposed upstream of the separations column for combining
a boil-off gas with the separations feed stream.
16) The apparatus according to claim 10, further comprising a
manifold disposed downstream of the separations column for
combining a boil-off gas with the overheads stream.
17) The apparatus of claim 10, further comprising a manifold
disposed downstream from the heat exchanger for combining the
combined boil-off gas and overheads stream with the vaporization
stream.
18) The apparatus of claim 10, further comprising a compressor for
compressing the boil-off gas stream.
Description
FIELD OF THE INVENTION
[0001] The present invention relates the heating value of liquefied
natural gas (LNG). More particularly, the present invention relates
to reducing the heating value of imported LNG by removing natural
gas liquid products while condensing boil-off gas.
BACKGROUND OF THE INVENTION
[0002] Natural gas is a valuable, environmentally-friendly energy
source. With gradually decreasing quantities of clean
easily-refined crude oil, natural gas has become accepted as an
alternative energy source. Natural gas may be recovered from
natural gas reservoirs or as associated gas from crude oil
reservoirs. Indeed, natural gas for use in the present process may
be recovered from any process which generates light hydrocarbon
gases.
[0003] Natural gas can be found all over the world. Much of the
natural gas reserves found around the world are separate from oil
and as new reserves are discovered and processed, growth in the LNG
industry will continue. Countries with large natural gas reservoirs
include Algeria, Australia, Brunei, Indonesia, Libya, Malaysia,
Nigeria, Oman, Qatar, and Trinidad and Tobago.
[0004] LNG terminals exist in Japan, South Korea, and Europe as
well as in the United States. LNG tankers can unload their cargo at
dedicated marine receiving terminals which store and regasify the
LNG for distribution to domestic markets. Onshore terminals can
include docks, LNG handling equipment, storage tanks, a vaporizer
system and interconnections to regional gas transmission pipelines
and electric power plants. Offshore terminals typically regasify
and pump the gas directly into offshore natural gas pipelines or
may store natural gas in undersea salt caverns for later injection
into offshore pipelines.
[0005] LNG is typically stored at cryogenic temperatures of about
-162.degree. C. and a vapor pressure at or near atmospheric
pressure in double walled tanks or containers. The core containment
for LNG is provided by the inner tank, while the outer tank is
designed to provide a secondary containment, hold insulation and
provide protection from adverse affects of the environment.
Conventional vaporizer systems are used to warm and convert the LNG
to usable gas. The LNG is warmed from approximately -160.degree. C.
in the vaporizer system converting it from a liquid phase to usable
gas to that it can be transferred to a pipeline.
[0006] As the LNG is being offloaded from the ship to the cryogenic
storage tank in an LNG receiving terminal, a portion of the
liquefied natural gas is vaporized due to several heating factors
such as pump heat, heat leak and flashing. These produced vapors
are compressed and either used for fuel or re-condensed by heat
exchanging with the LNG being pumped from the cryogenic storage
tank in a dedicated BOG condenser. The re-condensed vapors output
from the BOG condenser are then typically combined with the main
LNG stream that is pumped to the vaporizers and then gas pipeline
by LNG send out pumps.
[0007] Recently, consumers have been requiring strict
specifications for the LNG being re-gasified and sent out of their
LNG receiving terminals. These requirements include having the
correct calorific value, fuel quality and composition (C2, C3 and
heavier components). Since LNG liquefaction plants cannot be
efficiently modified so as to meet the strict specifications,
primarily due to the process operating conditions necessary to
liquefy the natural gas, separation of LNG C2+ components is
typically conducted in the LNG re-gasification terminal.
[0008] Natural gas liquid (NGL: refers to hydrocarbons found in
natural gas that can be extracted or isolated as liquefied
petroleum gas and natural gasoline) recovery at LNG re-gas
terminals is done in a number of ways, but all require the addition
of a number of complex rotating machinery items. For example, one
method requires a compressor to compress lean C1 gas up to pipeline
pressure while another requires that all LNG be pumped to an
intermediate pressure (between that of the LNG tank pumps and
send-out pumps) which adds a new step in the process.
[0009] The conventional process to capture BOG involves compressing
the gas to a pressure equal to that of the LNG which is being
pumped from the storage tanks. The BOG is combined with a stream of
LNG in a dedicated condenser vessel where it is re-condensed and
absorbed into the LNG. Another conventional process involves the
compressing of BOG to pipeline pressure and combining it downstream
of the vaporizers. This approach requires the compression of BOG to
a high pressure.
[0010] There is a need to develop a new methodology that provides a
better BOG handling and NGL recovery system while maintaining the
flexibility to satisfy different customer requirements. The new
methodology should also focus on reducing equipment capital costs
as well as operating expenses, while at the same time providing
reliable and safe operations.
SUMMARY OF THE INVENTION
[0011] The present invention achieves the advantage of a process
and apparatus for reducing the heating value of imported LNG by
removing liquid petroleum gas products with combined condensing of
boil-off gas.
[0012] In an aspect of the invention, a process for reducing the
heating value of LNG includes: splitting an LNG stream into a
separations feed stream and a vaporization feed stream; cross
heat-exchanging the separations feed stream with a combined
boil-off gas and overheads stream; separating the separations feed
stream into the overheads stream and a bottoms stream; and
combining the combined boil-off gas and overheads stream with the
vaporization feed stream.
[0013] Optionally, in the above process, a flowrate ratio between
the separations feed stream and the vaporization stream is in the
range of about 20:80 to 40:60.
[0014] Optionally, in the above process, the LNG stream pressure is
in the range of about 75 to 125 psig.
[0015] Optionally, in the above process, the LNG stream is at a dew
point temperature.
[0016] Optionally, in the above process, the separating is
performed in a demethanizer.
[0017] Optionally, in the above process, the combined boil-off gas
and overheads stream is formed by combining a boil-off gas stream
with the separations feed stream before the separations feed stream
is separated into the overheads stream and the bottoms stream.
[0018] Optionally, in the above process, the combined boil-off gas
and overheads stream is formed by combining a boil-off gas stream
with the overheads stream after the separations feed stream is
separated into the overheads stream and the bottoms stream.
[0019] Optionally, in the above process, the overheads stream
comprises at least about 98 mol % methane.
[0020] Optionally, in the above process, the cross heat-exchanging
of the separations feed stream with the combined boil-off gas and
overheads stream condenses at least a portion of the combined
boil-off gas and overheads stream.
[0021] In another aspect of the invention, an apparatus for
reducing the heating value of LNG includes: a pump for pumping an
LNG stream; a flow control device for splitting the LNG stream into
a separations feed stream and a vaporization stream; at least one
heat exchanger for cross heat-exchanging the separations feed
stream with a combined boil-off gas and overheads stream; and a
separations column for separating the separations feed stream into
the overheads stream and a bottoms stream.
[0022] Optionally, in the above apparatus, the flow control device
controls a flowrate ratio between the separations feed stream and
the vaporization stream within the range of about 20:80 to
40:60.
[0023] Optionally, in the above apparatus, the pump maintains the
LNG stream at a pressure in the range of about 75 to 125 psig.
[0024] Optionally, in the above apparatus, the LNG stream is at a
dew point temperature.
[0025] Optionally, in the above apparatus, the separations column
is a demethanizer.
[0026] Optionally, the above apparatus further includes a manifold
disposed upstream of the separations column for combining a
boil-off gas with the separations feed stream.
[0027] Optionally, the above apparatus further includes a manifold
disposed downstream of the separations column for combining a
boil-off gas with the overheads stream.
[0028] Optionally, the above apparatus further includes a manifold
disposed downstream from the heat exchanger for combining the
combined boil-off gas and overheads stream with the vaporization
stream.
[0029] Optionally, the above apparatus further includes a
compressor for compressing the boil-off gas stream.
DESCRIPTION OF THE DRAWINGS
[0030] FIG. 1 illustrates a flow diagram of an embodiment of the
invention.
DETAILED DESCRIPTION OF THE INVENTION
[0031] In the embodiment of the invention illustrated in FIG. 1, a
liquefied natural gas is maintained at a select pressure in a
container (B). Generally, the container is designed for a
particular pressure, and the temperature of the LNG equilibrates to
the bubble point temperature at the select pressure. However, it
will be readily understood that storing LNG at a temperature below
that of the bubble point is well within the range of current
technology, and that the present process encompasses the full range
of LNG storage temperatures The design of the container in which
LNG is stored is not critical to the invention, and includes
stationary storage located either on-shore or off-shore in an
aquatic location. Alternatively, the LNG may be stored in a mobile
container, located, for example, in a ship or on a truck, barge,
train or the like.
[0032] The present process can be employed with LNG stored over the
full range of possible storage pressure, including pressure from
ambient pressure to a pressure of 1500 psig and above. In one
embodiment, the LNG is stored at a pressure of about 5 psig or
less. In actual practice, it is preferred to maintain the LNG at a
storage pressure slightly above ambient pressure (e.g. 100-200 mbar
gauge) to ensure acceptable pressure control.
[0033] During the process of the present invention, LNG at (1) is
unloaded from an LNG carrier with on board pumps (A). The
pressurized LNG at (2) is then transferred to the LNG container
(B).
[0034] LNG (3) is transferred from the container (B) and
pressurized with a pump (C). The pressurized LNG (4) output from
the pump (C) is transferred to a heat exchanger (D), heated by
cross-exchange to a temperature close enough not to produce any
vapors (dew point temperature), and output as (5). The pressure of
the LNG at (4) is preferably in the range of about 75 to 125 psig
and the temperature change between (4) and (5) (across the heat
exchanger (D)) is in the range of about +25 to about +30.degree.
C.
[0035] The heat exchanger (D) is a gas direct-contact type
condenser such as a plate and fin exchanger in order to maximize
heat transfer.
[0036] The heated pressurized LNG (5) is split into a separations
feed stream (11) and a vaporization feed stream (6). The split in
flow may be achieved by using a flow control device such a valve
(not shown). The flowrate ratio is preferably in the range of about
20:80 to about 40:60 (20% to 40% for stream (11) and 80% to 60% for
stream (6)). By varying the flow ratio between stream (11) and
stream (6), the quantity of C2+ components in the pipeline gas can
be controlled to meet specific market requirements. The separations
feed stream (11) is further heated in a heat exchanger (H), which
is the same type of heat exchanger as the heat exchanger (D), and
output as a preheated LNG stream (12). The temperature change
between (11) and (12) (across the heat exchanger (H)) is in the
range of about +1 to about +5.degree. C.
[0037] The present invention is also directed, at least in part, to
a method for recovering BOG which is generated during LNG storage
and handling, prior to the LNG vaporization process. Since LNG is
maintained at a temperature below, and generally well below,
ambient temperature, a small amount of LNG will vaporize during
storage and handling as heat is absorbed through container walls.
To protect against an over-pressure condition in the LNG container
as the LNG vaporizer, the vaporized BOG must be handled. On account
of its value as an energy source, and the environmental penalty if
the BOG is vented to the atmosphere, it is desirable to recover and
reprocess the vented BOG.
[0038] Thus, boil-off gas (21) evolved in the LNG container (B) is
pressurized with a compressor (K) and output as (22). The
compressor (K) is either a centrifugal or reciprocating type
compressor.
[0039] The compressed boil-off gas (22) is then combined with the
preheated LNG stream (12) via a manifold (not shown), and the
combined stream (13) is transferred to a flash tank (I). The
combined stream (13) is then flashed into a vapor stream (17) and a
liquid stream (14). The flash tank (I) is a commonly used type low
pressure surge drum or phase separator drum.
[0040] The liquid stream (14) is then transferred to a demethanizer
column (J) and separated into an overheads stream (16) and an NGL
bottoms stream (15). The NGL bottoms stream (15) is sent to
additional processes.
[0041] The demethanizer column (J) is a reboiled absorber that uses
a bottom heat source, such as a bottoms reboiler. Other examples of
suitable bottom heat sources include a kettle reboiler, a
thermosyphon reboiler, a plate-fin exchanger, an internal reboiler,
a side reboiler, and combinations thereof. The demethanizer column
(J) typically includes a stripping section and an absorption
section within the same tower. In the demethanizer column (J), the
rising vapors in a reboiler reflux stream are at least partially
condensed by intimate contact with falling liquids from the liquid
stream (14), thereby producing the overheads stream (16). The
overheads stream (16) ha a methane concentration of at least about
98 mol %. The condensed liquids descend down the demethanizer
column (J) and are removed as the NGL bottoms stream (15).
[0042] The overheads stream (16) is combined with the vapor stream
(17) via a manifold (not shown) and output as a combined boil-off
gas and overheads stream (18). The combined boil-off gas and
overheads stream (18) is then transferred to the heat exchanger
(H), cooled and partially condensed by cross exchanging with the
LNG feed portion to the demethanizer (J), and output as (19). The
temperature change between (18) and (19) (across the heat exchanger
(H)) is in the range of about -3 to about -18.degree. C.
[0043] The cooled overheads stream (19) is further cooled and
condensed by cross exchanging with the LNG feed portion in the heat
exchanger (D), and output as (20). The temperature change between
(19) and (20) (across the heat exchanger(D)) is in the range of
about -3 to about -10.degree. C.
[0044] The cooled overheads stream (20) is then transferred to a
flash tank (L) and flashed into a vapor stream (23) and a liquids
stream (24). The vapor stream (23) is recycled back to the
container (B), while the liquids stream (24) is transferred to a
pump (M) and pressurized.
[0045] The vaporization feed stream (6) is combined, via a manifold
(not shown), with a pressurized liquid stream (25) output from the
pump (M), as (7).
[0046] The LNG (7) is then transferred to a flash tank (E) and
flashes into a vapor stream (26) and an LNG stream (8). The LNG
stream (8) is further pressurized with a pump (F) and output as
(9). The LNG stream (9) is then vaporized in a vaporizer (G) and
output as a gas (10).
[0047] Generally, the vaporization pressure will be set by the
pipeline delivery pressure at (10), increased by some relatively
small pressure differential to account for pressure losses across
the vaporizer (G). The LNG is vaporized when the pressurized LNG
(9) is passed across the vaporizer (G). Illustrative vaporizers
include shell and tube heat exchangers, open rack vaporizers and
the like. The vaporized LNG (10) is at pipeline delivery pressure,
and available for sending to a pipeline delivery system or to
another customer of natural gas. Generally the pipeline delivery
pressure to which the natural gas is compressed is greater than
1000 psig. A pressure in the region of 1300 psig is
illustrative.
[0048] The following tables are examples of a rich LNG case (Table
1) and a lean LNG case (Table 2). The methane concentration for the
rich LNG case is in the range of about 85 to 89 mol %. The methane
concentration for the lean LNG case is in the range of about 90 to
95 mol %.
TABLE-US-00001 TABLE 1 Rich LNG Stream No. Temperature Pressure
(FIG. 1) (.degree. C.) (bar) (psia) 1 -161 1.12 16.2 2 -161 6.85
99.4 3 -159 1.12 16.2 4 -159 7.91 115 5 -131 7.56 110 6 -131 7.56
110 7 -132 7.56 110 8 -132 7.56 110 9 -126 90.0 1305 10 15.0 89.3
1295 11 -131 7.56 110 12 -127 7.41 107 13 -127 7.41 107 14 -127
7.41 107 15 -13.3 7.56 110 16 -108 7.00 102 17 -127 7.41 107 18
-110 7.00 102 19 -125 6.80 98.6 20 -132 6.50 98.6 21 -159 1.12 16.2
22 -64.0 7.56 110 23 -132 6.50 94.3 24 -132 6.50 94.3 25 -132 7.56
110 26 -132 7.56 110
TABLE-US-00002 TABLE 2 Lean LNG Rich LNG Stream No. Temperature
Pressure Stream No. Temperature Pressure (FIG. 1) (.degree. C.)
(bar) (psia) (FIG. 1) (.degree. C.) (bar) (psia) 1 -161 1.12 16.2
14 -129 7.41 107 2 -161 6.85 99.4 15 -13.3 7.56 110 3 -160 1.12
16.2 16 -123 7.00 102 4 -159 7.91 115 17 -129 7.41 107 5 -130 7.56
110 18 -123 7.00 102 6 -130 7.56 110 19 -128 6.85 99.4 7 -131 7.56
110 20 -133 6.50 94.3 8 -131 7.56 110 21 -159 1.12 16.2 9 -124 90.0
1305 22 -66.2 7.56 110 10 15.0 89.3 1295 23 -133 6.50 94.3 11 -130
7.56 110 24 -133 6.50 94.3 12 -129 7.41 107 25 -132 7.56 110 13
-129 7.41 107 26 -131 7.56 110
* * * * *