U.S. patent application number 13/053809 was filed with the patent office on 2012-03-22 for nitrogen rejection and liquifier system for liquified natural gas production.
Invention is credited to Guillaume PAGES, Rustam H. SETHNA.
Application Number | 20120067079 13/053809 |
Document ID | / |
Family ID | 44673592 |
Filed Date | 2012-03-22 |
United States Patent
Application |
20120067079 |
Kind Code |
A1 |
SETHNA; Rustam H. ; et
al. |
March 22, 2012 |
NITROGEN REJECTION AND LIQUIFIER SYSTEM FOR LIQUIFIED NATURAL GAS
PRODUCTION
Abstract
A method for recovering liquefied natural gas from a gas mixture
containing natural gas and impurities by subjecting the natural gas
to a series of steps beginning with feeding a natural gas stream
containing impurities to a nitrogen rejection unit; feeding the
purified natural gas stream to a liquefier heat exchanger;
expanding the liquefied natural gas and feeding the expanded
liquefied natural gas to a flash vessel; flashing the liquid
natural gas and separating the liquefied natural gas from the flash
gas; and feeding the liquefied natural gas to storage and the flash
gas to the nitrogen rejection unit.
Inventors: |
SETHNA; Rustam H.; (Clinton,
NJ) ; PAGES; Guillaume; (Huningue, FR) |
Family ID: |
44673592 |
Appl. No.: |
13/053809 |
Filed: |
March 22, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61317466 |
Mar 25, 2010 |
|
|
|
Current U.S.
Class: |
62/611 |
Current CPC
Class: |
F25J 1/0264 20130101;
F25J 1/0022 20130101; F25J 2290/32 20130101; F25J 1/0291 20130101;
F25J 2245/02 20130101; F25J 1/0258 20130101; F25J 2220/62 20130101;
Y02E 50/30 20130101; C10L 3/105 20130101; F25J 2230/30 20130101;
F25J 1/0259 20130101; F25J 1/004 20130101; F25J 2210/06 20130101;
F25J 1/0279 20130101; F25J 1/0262 20130101; Y02E 50/346 20130101;
F25J 2245/90 20130101; F25J 2205/60 20130101; F25J 1/0219 20130101;
F25J 2290/62 20130101; F25J 1/0055 20130101; F25J 2210/66
20130101 |
Class at
Publication: |
62/611 |
International
Class: |
F25J 1/00 20060101
F25J001/00 |
Claims
1. A method for recovering liquefied natural gas comprising the
steps: feeding a natural gas stream containing impurities to a
nitrogen rejection unit; feeding the purified natural gas stream to
a liquefier heat exchanger; expanding the liquefied natural gas and
feeding the expanded liquefied natural gas to a flash vessel;
flashing the liquid natural gas and separating the liquefied
natural gas from the flash gas; and feeding the liquefied natural
gas to storage and the flash gas to said nitrogen rejection
unit.
2. The method as claimed in claim 1 wherein said impurities are
selected from the group consisting of water, carbon dioxide,
non-methane organic compounds and sulfur compounds.
3. The method as claimed in claim 1 wherein nitrogen is recovered
from said nitrogen rejection unit.
4. The method as claimed in claim 1 wherein the pressure in said
liquefier heat exchanger range from 6 to 30 bar.
5. The method as claimed in claim 1 wherein said liquefied natural
gas is expanded to a pressure of 1 to 5 bar.
6. The method as claimed in claim 1 wherein said flash gas is
richer in nitrogen than natural gas.
7. The method as claimed in claim 1 wherein said natural gas stream
is selected from the group consisting of landfill gas and
biogas.
8. The method as claimed in claim 1 wherein said flash gas is
recycled to said natural gas feed.
9. The method as claimed in claim 1 wherein flash pressure is lower
than storage pressure.
10. The method as claimed in claim 1 wherein said nitrogen
rejection unit is a vacuum swing adsorption unit.
11. The method as claimed in claim 1 wherein said recovered natural
gas is fed to a storage unit.
12. The method as claimed in claim 1 wherein said storage unit is
situated horizontally.
13. A method for recovering liquefied natural gas comprising the
steps: feeding a natural gas stream containing impurities to a
nitrogen rejection unit; feeding the purified natural gas stream to
a liquefier heat exchanger; expanding the liquefied natural gas and
feeding the expanded liquefied natural gas to a flash vessel;
flashing the liquid natural gas and separating the liquefied
natural gas from the flash gas; recovering refrigeration from said
flash gas; and feeding the liquefied natural gas to storage and the
flash gas to said nitrogen rejection unit.
14. The method as claimed in claim 13 wherein said impurities are
selected from the group consisting of water, carbon dioxide,
non-methane organic compounds and sulfur compounds.
15. The method as claimed in claim 13 wherein nitrogen is recovered
from said nitrogen rejection unit.
16. The method as claimed in claim 13 wherein the pressure in said
liquefier heat exchanger range from 6 to 30 bar.
17. The method as claimed in claim 13 wherein said liquefied
natural gas is expanded to a pressure of 1 to 5 bar.
18. The method as claimed in claim 13 wherein said flash gas is
richer in nitrogen than natural gas.
19. The method as claimed in claim 13 wherein said natural gas
stream is selected from the group consisting of landfill gas and
biogas.
20. The method as claimed in claim 13 wherein said flash gas is
recycled to said natural gas feed.
21. The method as claimed in claim 13 wherein flash pressure is
lower than storage pressure.
22. The method as claimed in claim 13 wherein said nitrogen
rejection unit is a vacuum swing adsorption unit.
23. The method as claimed in claim 13 wherein said recovered
natural gas is fed to a storage unit.
24. The method as claimed in claim 13 wherein said storage unit is
situated horizontally.
25. The method as claimed in claim 13 wherein said recovered
refrigeration provides cooling to a heat exchanger.
26. The method as claimed in claim 13 wherein said heat exchanger
is in thermal contact with the liquefier feed.
27. An apparatus comprising a nitrogen rejection unit, a liquefier
heat exchanger and a flash vessel.
28. The apparatus as claimed in claim 27 wherein said nitrogen
rejection unit is a vacuum swing adsorption unit.
29. The apparatus as claimed in claim 27 wherein said liquefier
heat exchanger is in thermal communication with said flash
vessel.
30. The apparatus as claimed in claim 27 wherein said nitrogen
rejection unit is in thermal communication with said liquefier heat
exchanger.
31. The apparatus as acclaimed in claim 27 wherein said flash
vessel is in fluid communication with a storage tank.
32. The apparatus as claimed in claim 27 further comprising a
second heat exchanger.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims priority from U.S. provisional
patent application Ser. No. 61/317,466, filed Mar. 25, 2010.
BACKGROUND OF THE INVENTION
[0002] The invention relates to the integration of a liquefied
natural gas (LNG) liquefier system with a nitrogen rejection unit
(NRU) so as to minimize the capital and operating costs while
maintaining liquefied natural gas product purity requirements.
[0003] Renewable methane can be recovered from a number of sources,
such as anaerobic digestion of municipal or industrial waste
streams, the degradation of biomass in landfills, the gasification
of waste and biomass streams, amongst others. In many instances,
this renewable methane require purification before it can be used
and/or sold into higher valued markets, such as injection into the
pipeline grid, as a feedstock for liquefied natural gas, as a
vehicle fuel, or as a feedstock for the production of hydrogen.
Further, the energy that is required to purify the renewable
methane is significant.
[0004] The cleanup of biogas/landfill gas is both capital and power
intensive because it contains a large number of trace and bulk
contaminants in fairly large concentrations. Various methods are
employed to remove these including chilling, cryogenic methods and
various adsorption and scrubbing processes. However, these
processes can be expensive in both capital and operating costs and
it is important to minimize these costs to achieve an economically
viable process.
[0005] A typical process for the purification of the methane from
biogas/landfill gas requires several steps. Sulfur removal is
generally followed by drying. The dried gas stream is then treated
for contaminants such a volatile organic compounds by process such
as adsorption, CO.sub.2 washing or by cryogenic methods. The stream
is then treated for bulk carbon dioxide removal by a membrane or
adsorption process and then is treated for removal of nitrogen. All
these purification steps are necessary before the biogas/landfill
gas can be liquefied and stored in anticipation of being dispensed,
or directed towards other uses, such as pipeline injection, energy
production with fuel cells or small-scale hydrogen production. LNG
production is particularly challenging since all condensable
contaminants including carbon dioxide must be removed to low ppm
levels.
[0006] The invention will allow for maximizing the methane recovery
while maintaining high liquefied natural gas product purity. The
operator can utilize a smaller nitrogen rejection unit and can
optimize power consumption. The process of using the nitrogen
rejection unit integrated with the liquefied natural gas liquefier
system achieves greater product purity (>96 mol % methane) and
greater than 89% methane recovery than conventional non-integrated
combinations.
[0007] By integration of the liquefied natural gas liquefier system
with a nitrogen rejection unit, the overall system becomes more
compact and efficient. This further enables the operator to
maximize methane recovery while maintaining high liquefied natural
gas product purity while enable a smaller nitrogen rejection unit.
The invention further allows the operator to optimize power
consumption while allowing for significantly higher product purity
and methane recovery than conventional or unitegrated NRU and
liquefier combinations which are limited to 96 mol % methane and
80% methane recovery.
SUMMARY OF THE INVENTION
[0008] The invention is a method for recovering liquefied natural
gas comprising the steps:
Feeding a natural gas stream containing impurities to a nitrogen
rejection unit; Feeding the purified natural gas stream to a
liquefier heat exchanger; Expanding the liquefied natural gas and
feeding the expanded liquefied natural gas to a flash vessel;
Flashing the liquid natural gas and separating the liquefied
natural gas from the flash gas; Feeding the liquefied natural gas
to storage and the flash gas to said nitrogen rejection unit.
[0009] Alternatively, the invention is a method for recovering
liquefied natural gas comprising the steps:
Feeding a natural gas stream containing impurities to a nitrogen
rejection unit; Feeding the purified natural gas stream to a
liquefier heat exchanger; Expanding the liquefied natural gas and
feeding the expanded liquefied natural gas to a flash vessel;
Flashing the liquid natural gas and separating the liquefied
natural gas from the flash gas; Recovering refrigeration from said
flash gas; and Feeding the liquefied natural gas to storage and the
flash gas to said nitrogen rejection unit.
[0010] The invention further comprises an apparatus comprising a
nitrogen rejection unit, a liquefier heat exchanger and a flash
vessel.
[0011] The raw feed gas is first compressed and pre-conditioned
which entails the removal of water, carbon dioxide, non-methane
organic compounds (NMOCs) and sulfur compounds by known methods.
The partially purified gas is fed to the nitrogen rejection unit
where much of the nitrogen is rejected. Since product purity and
methane recovery are inversely related, nitrogen rejection is
limited to maximize the methane recovery for the smallest equipment
cost. The resulting gas which contains significantly lower amounts
of inerts is fed to the liquefier heat exchanger where it is
liquefied at pressure to a subcooled state. Typical pressures range
from 30 bar to 6 bar with a tradeoff between mixed refrigeration
compressor power and compression power for the purification system.
This liquid is expanded through a valve whereby further cooling is
effected to about 2 bar (range is 1 to 5 bar).
[0012] The two-phase mixture is separated in a flash vessel and the
resulting liquid is directed to the storage tanks, while the flash
gas which is richer in nitrogen is recycled back to the nitrogen
rejection unit. The flash gas can also be combined with the raw
natural gas/biogas at the front end of the overall process if the
nitrogen rejection unit does not have a recycle compressor. Clearly
additional flash gas from the storage tank will be produced. This
too is recycled back to the nitrogen rejection unit or to the front
end of the cleanup process. The only methane that will be lost is
the nitrogen rejection unit waste stream which is nitrogen-rich but
otherwise very pure and can be flared or converted into power using
a gas engine or a fuel cell.
[0013] The end flash from the flash vessel has an additional
advantage in that the liquid outlet of a flash is at equilibrium
which implies that it will produce some more gas inside the line
between the end flash and storage tank because of product line
pressure drop. Therefore, it is best practice that the flash
pressure be lower than the storage pressure. To maximize liquefied
natural gas production and minimize product flash losses, the first
flash within the flash vessel is effected at a pressure lower than
the storage tank pressure, whence, the liquid coming down from the
end-flash tank will be sub-cooled at storage pressure. A cryogenic
pump can be utilized to overcome this concern, but involves
additional cost, maintenance and potential reliability issues.
Therefore it is advisable to have horizontal storage tanks, and a
cold box layout so that the liquid level inside the end flash will
be higher by a few hundreds of mbar of equivalent liquefied natural
gas head that the top of the storage and to use that additional
head to pressurize FIG. 2c.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] FIG. 1 is a typical mixed refrigerant liquefied natural gas
liquefier.
[0015] FIG. 2a is an integrated mixed refrigerant liquefied natural
gas liquefier.
[0016] FIG. 2b depicts a different embodiment of an integrated
mixed refrigerant liquefied natural gas liquefier.
[0017] FIG. 2c depicts another embodiment of an integrated mixed
refrigerant liquefied natural gas liquefier.
[0018] FIG. 3 shows methane recovery versus nitrogen rejection unit
product methane content.
[0019] FIG. 4 shows a liquefier embodied in the invention.
[0020] FIG. 5a shows a liquefier having a lower cost to
operate.
[0021] FIG. 5b shows a different embodiment of a lower cost to
operate liquefier.
DETAILED DESCRIPTION OF THE INVENTION
[0022] Landfill gas is purified and all the water, sulfur
compounds, NMOCs and carbon dioxide are removed in a
pre-purification process. The purified gas contains methane,
nitrogen and oxygen and has the following composition:
TABLE-US-00001 TABLE 1 NRU Feed Gas Composition Species Mole
Fraction Carbon Dioxide 0.0100 Nitrogen 0.2160 Methane 0.7720
Oxygen 0.0020
[0023] The gas is further purified in an adsorption system so that
the carbon dioxide level is reduced below 50 ppmv and a large
portion of the nitrogen is removed. Oxygen usually does not adsorb
appreciably and about 50% of the oxygen is removed in each case.
FIG. 1 illustrates a typical MR liquefier stream without process
integration. In this case both storage tank losses and nitrogen
rejection unit waste streams are not recovered.
[0024] Turning to the figures, FIG. 1, represents a base case mixed
refrigerant liquefied natural gas liquefier. Purified natural gas
is fed through line 1 through main heat exchanger A where it will
be warmed and fed through valve V1 and line 2 as liquefied natural
gas to a storage container, not shown.
[0025] A cold water stream (CWS) is fed through line 11 to heat
exchanger E as well as through valve V6 and line 13 to line 12 as
cold water return (CWR). The cold mixed refrigerant is fed through
line 9 to knockout drum B where it will proceed through line 7A to
refrigerant pump C and through open valve V4 to contact line 3 in
heat exchanger A. When valve V4 is closed and valve V5 is open the
mixed refrigerant will re-enter knock out drum B through line 7.
The overhead from knockout drum B will travel through line 3 to
heat exchanger A and enter valve V2 to column unit D where it will
exit unit D through overhead line 4 as well as through the bottom
of unit D through line 5A. This will exit heat exchanger A through
line 5 and connect to inlet separator G where the bottoms will
travel through line 8 and transfer pump H to line 6 which will
enter the knockout drum B. The refrigerant will leave the inlet
separator G through line 8A and connect to mixed refrigerant column
unit F where the mixed refrigerant will travel through line 10 back
to heat exchanger E.
[0026] In FIG. 2a, an integrated mixed refrigerant liquefied
natural gas liquefier system is shown per the operation of the
invention. Nitrogen containing biogas or other source of natural
gas such as landfill gas feed is fed through line 23 to nitrogen
rejection unit R which is typically a vacuum swing adsorption (VSA)
system. Waste gas is fed through line 25 to blower S and released
into the atmosphere. Depressurization gas is released through line
25A into line 22 where it will travel through recycle compressor Q
and reenter the nitrogen containing landfill or biogas feed line
23.
[0027] The nitrogen recovery unit product/liquefier feed natural
gas is fed through line 24 into heat exchanger I where it will pass
through valve V12 and enter flash tank J. The now liquefied natural
gas will exit through valve V11 and line 25 to line 26 where it
will enter storage tank K and can be accessed through line 21 and
valve V10 for later use. Vent gas from the storage tank K will exit
through line 20 where it will join line 22 and be fed back through
the recycle compressor Q to the nitrogen containing biogas feed
line 23.
[0028] Heat exchanger T is fed cold water through line 35A to
provide a cooling medium which will also feed to the cold water
return line 35 through valve V16. Line 24A directs warm water
leaving heat exchanger T. The cold refrigerant is fed through line
36 to knock out drum P which feeds the cold refrigerant to the heat
exchanger I through line 28 and which passes through valve V13 to
the column unit L where refrigerant from the top exits through line
31 and through the bottom through 31A which joins line 31 and
passes through heat exchanger I and line 31 will be fed to inlet
separator M where refrigerant exits through line 33 and is fed to
mixed refrigerant column unit U which feeds mixed refrigerant, now
warmer to the heat exchanger T through line 24. The bottoms from
the inlet separator M is fed through line 32 and transfer pump N
back to knock out drum P. The bottoms from the knockout drum P are
fed through line 30 and refrigerant pump O to valve V15 for reentry
back into the knockout drum P. BZ designates the cold box
boundary.
[0029] The refrigerant from the knockout drum P may also enter line
29 and open valve V14 where it will feed into line 31 and entry
into the inlet separator M.
[0030] FIG. 2b is a similar version of the integrated mixed
refrigerant liquefied natural gas liquefier system of FIG. 2A with
the numbering being the same as FIG. 2A. This embodiment has
compressor Q on line 23 rather than line 22 and no return line 25A
from the nitrogen rejection unit R to line 22. Also, line 30A
connects with valve V15A to heat exchanger I such that refrigerant
from knock out drum P is directed to the heat exchanger I.
[0031] FIG. 2c is another embodiment of the invention showing an
integrated mixed refrigerant liquefied natural gas liquefier.
Natural gas such as that from landfill gas or biogas from a
nitrogen recovery unit, not shown, is fed through line 40 into heat
exchanger V. The natural gas is liquefied and its pressure is
higher as it exits through line 40A through temperature control
valve V17. The liquefied natural gas enters end flash unit W where
the flashed liquefied natural gas is fed through line 41 and open
pressure control valve V18 and recycled back to heat exchanger V
where it will exit and be fed through line 42 to a nitrogen
recovery unit, not shown.
[0032] The bottoms from the flash unit W exit through line 43 and
open valve V19 where it will enter horizontal cryogenic storage
tank Y. Additional static head is maintained between the liquid
level in the end flash unit W and the horizontal cryogenic storage
tank Y such that it is equivalent to subcooling at storage level
and pressure. Line BZ represents the cold box boundary.
[0033] FIG. 3 shows the effect of methane product purity on methane
recovery. Methane recovery decreases as the nitrogen recovery unit
product methane content in mole % increases.
[0034] FIG. 4 shows a preferred liquefier embodiment. Natural gas
such as that found in landfill gas or biogas is fed through line 64
to heat exchanger AA where it will exit as liquefied natural gas
through open valve V20 and be fed to flash tank AB. The liquefied
natural gas from the bottoms of the flash tank AB will exit through
line 66 and open valve V22 where it will be fed to storage, not
shown. The gaseous natural gas tops of the flash tank will exit
through line 65 and re-enter heat exchanger AA where it will be fed
to a mixed gas nitrogen recovery unit, not shown.
[0035] Cold water is fed through line 60 into heat exchanger AI to
provide a cooling medium and also fed through line 61 and open
valve V25 to the cold water return line 62. Refrigerant will exit
through line 64 and be fed through to a knockout drum AD where
refrigerant is fed through line 51 and refrigerant pump AE through
open valve V24 to line 52 passing through heat exchanger AA. When
valve V24 is closed and valve V24A is open, the refrigerant is fed
through line 55 back to knockout drum AD. Refrigerant is also fed
through line 56 from the top of the knockout drum AD to line 52
passing through heat exchanger AA. Line 52 will deliver the
refrigerant through open valve V21 to a column unit AC where the
bottoms from said unit are fed through line 53 to rejoin with the
tops which exit unit AC through line 54. Line 54 passes through
heat exchanger AA where it will be fed to inlet separator AF.
[0036] The refrigerant in line 54 is occasionally supplemented from
the knockout drum AD through open valve V23 and line 57 which
connects with the tops from the knockout drum AD through line 56.
Line 54 will enter the inlet separator AF where its bottoms are
transferred through line 58A and transfer pump AG to line 50 which
returns to the knockout drum AD. The tops from the inlet separator
AF exit through line 58 and enter mixed refrigerant column unit AH
where mixed refrigerant will enter the heat exchanger AI for
cooling and reentry into the knockout drum AD for entry into heat
exchanger AA.
[0037] FIG. 5a shows a lower cost embodiment liquefier. Natural gas
such as that found in landfill gas or biogas is fed through line 79
and open valve V30 where it will enter flash tank BA. Liquefied
natural gas exits through line 77 and open valve V33 to storage,
not shown. Natural gas will exit the flash tank BA through line 78
where it will pass through economizer BC and exit to a nitrogen
recovery unit, not shown. Valve V32 can be opened and excess
nitrogen can be recovered through line 78A, unit TIC back into
flash tank BA.
[0038] Part of the natural gas feed from line 78 is fed through
open valve V31 to line 76 which passes through heat exchanger BD
and open valve V34 back to the flash tank BA as liquefied natural
gas.
[0039] Cold water is fed through line 83 to heat exchanger BJ and
through line 85 and open valve V39 to cold water return line 84.
Refrigerant will exit through line 85A and be fed to knockout drum
BH where it will exit through the bottom of the knockout drum
through open valve V36 and refrigerant pump BI to be fed to line 74
passing through heat exchanger BD. Valve V36 can be closed and
valve V38 open such that refrigerant will pass through line 75 back
to knockout drum BR
[0040] The tops from the knockout drum BH will be fed through line
70 to line 74 passing through heat exchanger BD. The refrigerant
will pass through open valve V35 and be fed to column unit BE where
the bottoms from the unit exit through line 71 and join with the
tops from the unit BE line 72 which passes refrigerant through heat
exchanger BD. This refrigerant will enter inlet separator BG
through line 72 where the bottoms from the inlet separator BG are
fed through line 80 and transfer pump BF back to the knockout drum
BH.
[0041] The tops from the inlet separator will exit through line 81
to mixed refrigerant unit BK. The mixed refrigerant from unit BK is
fed back to heat exchanger BJ as a warm fluid through line 82 where
it will be cooled down and ultimately fed back into heat exchanger
BD after passing through knockout drum BH. Line BZ designates the
cold box boundary.
[0042] FIG. 5b is virtually identical to FIG. 5a designating a
lower cost liquefier embodiment. In this embodiment, the numbering
is the same and there is no return embodiment on top of the flash
tank BA, thus line 78A, valve V32 and TIC control mechanism are not
present. In FIG. 5b, the cold box boundary BZ is also broader and
covers the flash tank BA which is not seen in FIG. 5a.
[0043] Typical nitrogen rejection performance is shown in FIG. 3
for a vacuum swing adsorption (VSA) nitrogen rejection unit. The
invention is shown in FIG. 2a. The nitrogen rejection amount was
varied while ensuring that the final LNG product contained
98%+methane. Three cases were considered for illustrative purposes
where the NRU product/liquefier feed gas contained 90.6, 98.2 and
98% methane (C1). The relative equipment size, which determines
capital cost and the power were calculated and compared. The
results are as indicated in Tables 2 and 3 below. In Table 2, both
the pre-cleanup system, which is used to remove all contaminants
other than nitrogen and oxygen, and the four bed VSA system are
compared in terms of size which is directly proportional to the
kg-moles/hr of NRU feed to be processed or the nitrogen to be
rejected. Case 3 clearly shows significant benefits when a less
pure NRU product is fed to the liquefier with a pre-cleanup system
that is 17% smaller and a NRU that is 23% smaller than the first
case.
TABLE-US-00002 TABLE 2 Effect of Liquefier Feed Composition on
Overall Methane Recovery and Equipment Size C1 in Liquefier
Pre-Cleanup NRU Wobbe Index Feed (mol %) Relative Size Relative
Size (MJ/m.sup.3) Case 1 98.0 1.17 1.23 50.37 Case 2 96.2 1.06 1.10
50.11 Case 3 90.6 1.00 1.00 49.35
[0044] In addition, the relative power for all 3 cases is compared
in Table 3 which shows that the extra power needed for liquefaction
and recycle with higher inerts (case 1) is compensated by the
vacuum pump power needed for higher NRU purity (case 3). Hence,
there is no appreciable net power penalty.
TABLE-US-00003 TABLE 3 Effect of Liquefier Feed Composition on Net
Power C1 in Liquefier Feed Relative Power (mol %) (%) Case 1 98.0
100.5 Case 2 96.2 99.6 Case 3 90.6 100.0
[0045] Other embodiments of the invention are illustrated in FIGS.
5a and 5b, both of which are lower capital cost options and do not
require a separate pass in the main heat exchanger, or a larger
coldbox. Nevertheless, both embodiments do not allow for full cold
recovery and are less efficient. Additionally, if all the purified
natural gas from the NRU is fed to the economizer, a very large
temperature gradient will result at the cold end of this exchanger.
Therefore, it is desired that only a portion of the NRU product is
fed to the economizer so that it can be liquefied, or cooled close
to the liquefaction temperature. The portion of the NRU product gas
cooled in the economizer can be sent to flash tank labeled BA in
FIGS. 5a and 5b as sub-cooled liquid or to the main heat
exchanger.
[0046] While this invention has been described with respect to
particular embodiments thereof, it is apparent that numerous other
forms and modifications of the invention will be obvious to those
skilled in the art. The appended claims in this invention generally
should be construed to cover all such obvious forms and
modifications which are within the true spirit and scope of the
invention.
* * * * *