U.S. patent application number 13/264345 was filed with the patent office on 2012-02-16 for nitrogen rejection methods and systems.
This patent application is currently assigned to Exxonmobil Upstream Research Company. Invention is credited to Edward L Kimble, Peter C Rasmussen.
Application Number | 20120036890 13/264345 |
Document ID | / |
Family ID | 43085265 |
Filed Date | 2012-02-16 |
United States Patent
Application |
20120036890 |
Kind Code |
A1 |
Kimble; Edward L ; et
al. |
February 16, 2012 |
NITROGEN REJECTION METHODS AND SYSTEMS
Abstract
Methods and systems for removing nitrogen from a natural gas
feed stream. The systems and methods generally include a heat
exchange unit, a separation unit, and a liquid methane pump unit,
where the separation unit produces a liquid methane bottoms stream
and a gaseous overhead stream enriched in nitrogen and the liquid
methane pump unit compresses the liquid methane bottoms stream and
then pumps the stream through the heat exchange unit to cool a
natural gas feed stream. In some embodiments the liquid methane
pump unit is a sleeve bearing type unit. Beneficially, the
disclosed systems and methods incorporate high head pumps for
liquid methane compression instead of vaporizing the liquid methane
and compressing it in a gaseous compression units that are
typically used for this purpose, saving space, materials, and
power.
Inventors: |
Kimble; Edward L; (Sugar
Land, TX) ; Rasmussen; Peter C; (Conroe, TX) |
Assignee: |
Exxonmobil Upstream Research
Company
Houston
TX
|
Family ID: |
43085265 |
Appl. No.: |
13/264345 |
Filed: |
March 8, 2010 |
PCT Filed: |
March 8, 2010 |
PCT NO: |
PCT/US10/26507 |
371 Date: |
October 13, 2011 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61178328 |
May 14, 2009 |
|
|
|
Current U.S.
Class: |
62/620 ;
62/927 |
Current CPC
Class: |
F25J 2200/70 20130101;
F25J 3/061 20130101; F25J 3/0635 20130101; F25J 2200/02 20130101;
F25J 3/0209 20130101; F25J 3/066 20130101; F25J 3/0257 20130101;
F25J 2240/40 20130101; F25J 2230/60 20130101; F25J 2235/60
20130101; F25J 2260/60 20130101; F25J 2280/02 20130101; F25J
2205/04 20130101; F25J 3/0233 20130101; F25J 2290/42 20130101; F25J
2230/42 20130101 |
Class at
Publication: |
62/620 ;
62/927 |
International
Class: |
F25J 3/00 20060101
F25J003/00 |
Claims
1. A nitrogen rejection system, comprising: a natural gas feed
stream comprising nitrogen and methane and having a temperature
above cryogenic conditions; a feed stream heat exchanger configured
to reduce the temperature of the natural gas feed stream to form a
majority liquefied natural gas feed stream; a separation unit
configured to receive the cooled natural gas feed stream and
produce an overhead stream enriched in nitrogen and a bottoms
stream enriched in methane ("liquefied methane stream"); and a
liquid methane pump configured to pump the liquefied methane stream
to a sales compression pressure to form a pressurized liquefied
methane stream, wherein the pressurized liquefied methane stream is
substantially vaporized in the feed stream heat exchanger to form a
methane product stream.
2. The system of claim 1, wherein the liquid methane pump is a
sleeve bearing type pump.
3. The system of claim 2, wherein the liquid methane pump comprises
a magnetic thrust bearing configured to reduce a gravity thrust
load on an axial bearing of the liquid methane pump.
4. The system of claim 3, wherein the configuration of the sleeve
bearing type pump is selected from the group consisting of: a
single pump, a series of at least two pumps, a parallel
configuration of at least two pumps, a multistage pump, and any
combination thereof.
5. The system of claim 3, wherein the separation unit is configured
to operate at a pressure of at least about 200 pounds per square
inch (psi) to about 500 psi and a temperature of at least about
-220 degrees Fahrenheit (.degree. F.) to about -120.degree. F.
6. The system of claim 5, wherein the separation unit is a tower
having a top feed stripper portion and a lower cryogenic reboiler
portion configured to separate gaseous nitrogen from the liquefied
methane stream.
7. The system of claim 5, wherein at least a portion of the
overhead stream enriched in nitrogen is fed to the feed stream heat
exchanger to form a warmed nitrogen enriched stream.
8. The system of claim 7, further comprising: a compressor
configured to compress the warmed nitrogen enriched stream to form
a compressed nitrogen enriched stream; and a nitrogen rejection
unit (NRU) configured to receive the compressed nitrogen enriched
stream to form a methane enriched stream.
9. The system of claim 8, wherein the warmed nitrogen stream is
less than about 50 volume percent (vol %) of the natural gas feed
stream.
10. The system of claim 5, wherein at least a portion of the
overhead stream enriched in nitrogen is fed to a power generation
unit configured to generate power using the at least a portion of
the overhead stream enriched in nitrogen.
11. The system of claim 5, further comprising: a reboiler feed
stream from the separation unit; a slip stream from the
substantially liquefied natural gas feed stream; and a reboiler
heat exchanger configured to exchange heat energy from the slip
stream to the reboiler feed stream to generate a nitrogen
containing vapor from the reboiler feed stream, wherein the slip
stream is then re-mixed with the substantially liquefied natural
gas feed stream.
12. The system of claim 11, further comprising an expansion device
configured to receive the substantially liquefied natural gas feed
stream and hold a back-pressure on a feed condensing pass of the
feed stream heat exchanger, wherein the expansion device is
selected from the group consisting of a flow control device, a
level control device, a back-pressure control valve, and any
combination thereof.
13. The system of claim 11, further comprising: a feed separator
configured to produce a nitrogen enriched gas stream and a bottoms
stream enriched in methane; and at least one level control valve
configured to maintain a liquid level in the feed separator.
14. The system of any one of claims 12-13, further comprising a
flow integrated controller configured to control at least the
back-pressure on the feed condensing pass of the feed stream heat
exchanger.
15. A method of nitrogen rejection, comprising: cooling a natural
gas feed stream comprising nitrogen and methane in a feed stream
heat exchanger to form a majority liquefied natural gas feed
stream; separating the substantially liquefied natural gas feed
stream in a separator to produce an overhead stream enriched in
nitrogen and a liquid bottoms stream enriched in methane
("liquefied methane stream"); pressurizing the liquefied methane
stream in a liquid methane pump to a sales compression pressure to
form a pressurized liquefied methane stream; and exchanging heat
from the natural gas feed stream to the pressurized liquefied
methane stream in the feed stream heat exchanger to form a methane
product stream.
16. The method of claim 15, wherein the liquid methane pump is a
sleeve bearing type pump.
17. The method of claim 16, wherein the liquid methane pump
comprises a magnetic thrust bearing configured to reduce a gravity
thrust load on an axial bearing of the liquid methane pump.
18. The method of claim 17, wherein the configuration of the sleeve
bearing type pump is selected from the group consisting of: a
single pump, a series of at least two pumps, a parallel
configuration of at least two pumps, a multistage pump, and any
combination thereof.
19. The method of claim 17, wherein the separation unit is
configured to operate at a pressure of at least about 200 pounds
per square inch (psi) to about 500 psi and a temperature of at
least about -220 degrees Fahrenheit (.degree. F.) to about
-120.degree. F.
20. The system of claim 19, wherein the separation unit is a tower
having a top feed stripper portion and a lower cryogenic reboiler
portion configured to separate gaseous nitrogen from the liquefied
methane stream.
21. The method of claim 19, further comprising feeding at least a
portion of the overhead stream enriched in nitrogen to the feed
stream heat exchanger to form a warmed nitrogen enriched
stream.
22. The method of claim 21, further comprising: compressing the
warmed nitrogen enriched stream in a compressor to form a
compressed nitrogen enriched stream; and feeding the compressed
nitrogen enriched stream to a nitrogen rejection unit (NRU) to form
a methane enriched stream.
23. The method of claim 22, wherein the warmed nitrogen stream is
less than about 50 volume percent (vol %) of the natural gas feed
stream.
24. The method of claim 19, further comprising: feeding at least a
portion of the overhead stream enriched in nitrogen to a power
generation unit; and generating power in the power generation
unit.
25. The method of claim 19, further comprising: taking a reboiler
feed stream from the separation unit; taking a slip stream from the
substantially liquefied natural gas feed stream; exchanging heat
energy from the slip stream to the reboiler feed stream in a
reboiler heat exchanger to generate a nitrogen containing vapor
from the reboiler feed stream; and re-mixing the slip stream with
the substantially liquefied natural gas feed stream.
26. The method of claim 25, further comprising: maintaining a
back-pressure on a feed condensing pass of the feed stream heat
exchanger using an expansion device configured to receive the
substantially liquefied natural gas feed stream, wherein the
expansion device is selected from the group consisting of a flow
control device, a level control device, a back-pressure control
valve, and any combination thereof.
27. The method of claim 25, further comprising: producing a
nitrogen enriched gas stream and a bottoms stream enriched in
methane in a feed separator; and maintaining a liquid level in the
feed separator using a level control valve.
28. The method of any one of claims 26-27, further comprising
controlling at least the back-pressure on a feed condensing pass of
the feed stream heat exchanger and the back-pressure on the
separation unit using flow integrated controller.
29. The nitrogen rejection system of claim 1, wherein the liquefied
methane stream comprises ethane and heavier hydrocarbons.
30. The method of nitrogen rejection of claim 15, wherein the
liquefied methane stream comprises ethane and heavier hydrocarbons.
Description
CROSS REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the benefit of U.S. Provisional
Application No. 61/178,328 filed May 14, 2009.
FIELD OF THE INVENTION
[0002] Embodiments of the disclosed invention relate to nitrogen
rejection methods and systems. More particularly, embodiments of
the disclosed invention relate to methods and systems for
efficiently reducing the nitrogen concentration of a natural gas
production stream.
BACKGROUND OF THE INVENTION
[0003] This section is intended to introduce various aspects of the
art, which may be associated with exemplary embodiments of the
present disclosure. This discussion is believed to assist in
providing a framework to facilitate a better understanding of
particular aspects of the present disclosure. Accordingly, it
should be understood that this section should be read in this
light, and not necessarily as admissions of prior art.
Description of the Related Art
[0004] Natural gas is one of the world's fastest growing and most
significant sources of energy. It is highly desirable due to it's
availability, relative price, and its reduced environmental impact
over coal and other sources of energy generation. Gas fields, some
containing recoverable hydrocarbon condensates and/or C2, C3, C4,
and C5 natural gas liquids (NGL) components, face the challenge of
separating nitrogen from the methane-rich stream in order to meet
the energy content (often measured in BTU/scf) requirements for
methane gas sales contracts. The separation of nitrogen from
methane is technically challenging because the gases have similar
size, chemical nature, and boiling point. The additional complexity
of nitrogen separation and the compression normally associated with
nitrogen removal from methane-rich streams combine to increase the
area footprint and weight of the facilities involved. Efficiently
reducing the nitrogen content of produced natural gas streams is
one of the world's toughest energy challenges.
[0005] In a standard cryogenic distillation process used for high
flow rate applications, the natural gas feed stream is routed
repeatedly through a column and a heat exchanger (typically a
brazed aluminum plate-fin type), where the nitrogen is
cryogenically separated and vented. This approach is very capital
intensive as a lot of aluminum is needed. Further, the final
methane product is typically produced at low pressure, so
re-pressurization is needed, which is almost always accomplished
via energy-intensive compressors. Other existing processes include
pressure swing adsorption (PSA), membrane separation, lean oil
absorption, and solvent absorption.
[0006] Existing cryogenic distillation processes require large,
expensive, complex pieces of equipment to reduce the nitrogen
(N.sub.2) content of produced natural gas. In particular, existing
cryogenic distillation nitrogen rejection units (NRU's) also
require large quantities of aluminum for fabrication. Another
problem with current processes is the significant amount of energy
required to compress the methane up to a sufficient pressure for
pipeline transport to the destination market.
[0007] NRU processes other than cryogenic distillation also
generally result in large capital expenditure, complexity, and high
power consumption costs due to the needed compression and other
factors.
[0008] One example of a common cryogenic nitrogen rejection
approach is found in U.S. Pat. No. 7,520,143 (the '143 patent),
which discloses a dual stage cryogenic distillation type nitrogen
rejection unit (NRU) that produces a low pressure, low temperature
liquefied natural gas stream having less than 1.5 mol % nitrogen, a
nitrogen vent stream having over 98 mol % nitrogen content, and a
fuel stream with a nitrogen content of about 30 mol %.
[0009] What is needed are methods and systems of more efficiently
separating nitrogen from natural gas in natural gas production
operations.
[0010] Other relevant information may be found in U.S. Pat. No.
4,890,988; COYLE, DAVID A., PATEL, VINOD, Processes and Pump
Services in the LNG Industry, Proceedings of the Int'l Pump Users
Symposium (2005); and "Rejection Strategies," Hydrocarbon
Engineering, October 2007 pp. 49-52.
SUMMARY OF THE INVENTION
[0011] In one embodiment of the present invention a nitrogen
rejection system is provided. The nitrogen rejection system
includes a natural gas feed stream comprising nitrogen and methane
and having a temperature above cryogenic conditions; a feed stream
heat exchanger configured to reduce the temperature of the natural
gas feed stream to form a majority liquefied natural gas feed
stream; a separation unit configured to receive the cooled natural
gas feed stream and produce an overhead stream enriched in nitrogen
and a bottoms stream enriched in methane ("liquefied methane
stream"); and a liquid methane pump configured to pump the
liquefied methane stream to a sales compression pressure to form a
pressurized liquefied methane stream, wherein the pressurized
liquefied methane stream is substantially vaporized in the feed
stream heat exchanger to form a methane product stream. In some
embodiments, the liquid methane pump is a sleeve bearing type pump
and may further include a magnetic thrust bearing configured to
reduce a gravity thrust load on an axial bearing of the liquid
methane pump and may be configured as a single pump, a series of at
least two pumps, a parallel configuration of at least two pumps, a
multistage pump, and any combination thereof.
[0012] In some embodiments, the separation unit is configured to
operate at a pressure of at least about 200 pounds per square inch
(psi) to about 500 psi and a temperature of at least about -220
degrees Fahrenheit (.degree. F.) to about -120.degree. F. and may
be a tower having a top feed stripper portion and a lower cryogenic
reboiler portion configured to separate gaseous nitrogen from the
liquefied methane stream. In additional embodiments, at least a
portion of the overhead stream enriched in nitrogen is fed to the
feed stream heat exchanger to form a warmed nitrogen enriched
stream. The system may further include a compressor configured to
compress the warmed nitrogen enriched stream to form a compressed
nitrogen enriched stream; and a nitrogen rejection unit (NRU)
configured to receive the compressed nitrogen enriched stream to
form a methane enriched stream, wherein the warmed nitrogen stream
is less than about 50 volume percent (vol %) of the natural gas
feed stream. Alternatively, a portion of the overhead stream
enriched in nitrogen may be fed to a power generation unit
configured to generate power using the at least a portion of the
overhead stream enriched in nitrogen.
[0013] In still another alternative embodiment of the system, the
system further includes a reboiler feed stream from the separation
unit; a slip stream from the substantially liquefied natural gas
feed stream; a reboiler heat exchanger configured to exchange heat
energy from the slip stream to the reboiler feed stream to generate
a nitrogen containing vapor from the reboiler feed stream, wherein
the slip stream is then re-mixed with the substantially liquefied
natural gas feed stream; and an expansion device configured to
receive the substantially liquefied natural gas feed stream and
hold a back-pressure on a feed condensing pass of the feed stream
heat exchanger, wherein the expansion device is selected from the
group consisting of a flow control device, a level control device,
a back-pressure control valve, and any combination thereof.
Alternatively, the system may include a feed separator configured
to produce a nitrogen enriched gas stream and a bottoms stream
enriched in methane; and at least one level control valve
configured to maintain a liquid level in the feed separator. In a
further embodiment, the system may include a flow integrated
controller configured to control at least the back-pressure on the
feed condensing pass of the feed stream heat exchanger.
[0014] In a second major embodiment of the disclosure, a method of
nitrogen rejection is disclosed. The method includes cooling a
natural gas feed stream comprising nitrogen and methane in a feed
stream heat exchanger to form a majority liquefied natural gas feed
stream; separating the substantially liquefied natural gas feed
stream in a separator to produce an overhead stream enriched in
nitrogen and a liquid bottoms stream enriched in methane
("liquefied methane stream"); pressurizing the liquefied methane
stream in a liquid methane pump to a sales compression pressure to
form a pressurized liquefied methane stream; and exchanging heat
from the natural gas feed stream to the pressurized liquefied
methane stream in the feed stream heat exchanger to form a methane
product stream. In some embodiments, the liquid methane pump is a
sleeve bearing type pump and further comprises a magnetic thrust
bearing configured to reduce a gravity thrust load on an axial
bearing of the liquid methane pump, which may be configured as a
single pump, a series of at least two pumps, a parallel
configuration of at least two pumps, a multistage pump, or any
combination thereof.
[0015] Additional embodiments may provide that the separation unit
is configured to operate at a pressure of at least about 200 pounds
per square inch (psi) to about 500 psi and a temperature of at
least about -220 degrees Fahrenheit (.degree. F.) to about
-120.degree. F. or that the separation unit is a tower having a top
feed stripper portion and a lower cryogenic reboiler portion
configured to separate gaseous nitrogen from the liquefied methane
stream. The method may further include feeding at least a portion
of the overhead stream enriched in nitrogen to the feed stream heat
exchanger to form a warmed nitrogen enriched stream, compressing
the warmed nitrogen enriched stream in a compressor to form a
compressed nitrogen enriched stream; and feeding the compressed
nitrogen enriched stream to a nitrogen rejection unit (NRU) to form
a methane enriched stream, wherein the warmed nitrogen stream is
less than about 50 volume percent (vol %) of the natural gas feed
stream.
[0016] In a further alternative embodiment, the method may include
feeding at least a portion of the overhead stream enriched in
nitrogen to a power generation unit; and generating power in the
power generation unit.
[0017] In yet another alternative embodiment, the method may
include taking a reboiler feed stream from the separation unit;
taking a slip stream from the substantially liquefied natural gas
feed stream; exchanging heat energy from the slip stream to the
reboiler feed stream in a reboiler heat exchanger to generate a
nitrogen containing vapor from the reboiler feed stream; re-mixing
the slip stream with the substantially liquefied natural gas feed
stream; and maintaining a back-pressure on a feed condensing pass
of the feed stream heat exchanger using an expansion device
configured to receive the substantially liquefied natural gas feed
stream, wherein the expansion device is selected from the group
consisting of a flow control device, a level control device, a
back-pressure control valve, and any combination thereof.
[0018] In still another alternative, the method may include
producing a nitrogen enriched gas stream and a bottoms stream
enriched in methane in a feed separator; and maintaining a liquid
level in the feed separator using a level control valve. The method
may further provide for controlling at least the back-pressure on a
feed condensing pass of the feed stream heat exchanger and the
back-pressure on the separation unit using flow integrated
controller.
BRIEF DESCRIPTION OF THE DRAWINGS
[0019] The foregoing and other advantages of the present invention
may become apparent upon reviewing the following detailed
description and drawings of non-limiting examples of embodiments in
which:
[0020] FIG. 1 is a schematic illustration of a system in accordance
with certain aspects of the disclosure;
[0021] FIG. 2 is a flow chart illustrating of a process in
accordance with certain aspects of the system of FIG. 1;
[0022] FIGS. 3A-3C are schematics of several exemplary alternative
embodiments of the system of FIG. 1;
[0023] FIG. 4 illustrates a chart showing a temperature heat flow
plot for comparing heat flow between hot and cold streams.
DETAILED DESCRIPTION
[0024] In the following detailed description section, the specific
embodiments of the present disclosure are described in connection
with preferred embodiments. However, to the extent that the
following description is specific to a particular embodiment or a
particular use of the present disclosure, this is intended to be
for exemplary purposes only and simply provides a description of
the exemplary embodiments. Accordingly, the disclosure is not
limited to the specific embodiments described below, but rather, it
includes all alternatives, modifications, and equivalents falling
within the true spirit and scope of the appended claims.
Definitions
[0025] Various terms as used herein are defined below. To the
extent a term used in a claim is not defined below, 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.
[0026] As used herein, "a" or "an" entity refers to one or more of
that entity. As such, the terms "a" (or "an"), "one or more", and
"at least one" can be used interchangeably herein unless a limit is
specifically stated.
[0027] As used herein, the term "enriched" as applied to any stream
withdrawn from a process means that the withdrawn stream contains a
concentration of a particular component that is higher than the
concentration of that component in the feed stream to the
process.
[0028] As used herein, the term "expansion device" refers to one or
more devices suitable for reducing the pressure of a fluid in a
line (for example, a liquid stream, a vapor stream, or a multiphase
stream containing both liquid and vapor). Unless a particular type
of expansion device is specifically stated, the expansion device
may be (1) at least partially by isenthalpic means, or (2) may be
at least partially by isentropic means, or (3) may be a combination
of both isentropic means and isenthalpic means. Suitable devices
for isenthalpic expansion of natural gas are known in the art and
generally include, but are not limited to, manually or
automatically actuated throttling devices such as, for example,
valves, control valves, Joule-Thomson (J-T) valves, or venturi
devices. Suitable devices for isentropic expansion of natural gas
are known in the art and generally include equipment such as
expanders or turbo expanders that extract or derive work from such
expansion. Suitable devices for isentropic expansion of liquid
streams are known in the art and generally include equipment such
as expanders, hydraulic expanders, liquid turbines, or turbo
expanders that extract or derive work from such expansion. An
example of a combination of both isentropic means and isenthalpic
means may be a Joule-Thomson valve and a turbo expander in
parallel, which provides the capability of using either alone or
using both the J-T valve and the turbo expander simultaneously.
Isenthalpic or isentropic expansion can be conducted in the
all-liquid phase, all-vapor phase, or mixed phases, and can be
conducted to facilitate a phase change from a vapor stream or
liquid stream to a multiphase stream (a stream having both vapor
and liquid phases). In the description of the drawings herein, the
reference to more than one expansion device in any drawing does not
necessarily mean that each expansion device is the same type or
size.
[0029] As used herein, the term "indirect heat exchange" means the
bringing of two fluids into heat exchange relation without any
physical contact or intermixing of the fluids with each other.
Core-in-kettle heat exchangers and brazed aluminum plate-fin heat
exchangers are specific examples of equipment that facilitate
indirect heat exchange.
[0030] As used herein, the term "compressor" means a machine that
increases the pressure of a gas by the application of work.
[0031] As used herein, the term "liquid methane pump" means a
device for increasing the head of a fluid stream at cryogenic
conditions. More specifically, the liquid methane pump is limited
to the types of pumps used in processing liquefied natural gas
(LNG) and therefore will be capable of pressurizing liquid methane
from at least about 200 pounds per square inch (psi) to about 1,200
psi at a flow rate of from at least about 1,000 cubic meters per
hour (m.sup.3/hr) to about 2,500 m.sup.3/hr and up to about 25,000
m.sup.3/day.
[0032] As used herein, the term "reboiler heat exchanger" refers to
an indirect heat exchange means used to at least partially vaporize
a stream withdrawn near the bottom of a separation unit or feed
separator.
[0033] As used herein, the term "bottoms stream" or "bottoms
product" refers to an at least partially liquid stream withdrawn
from at or near the bottom portion of a separation unit or
separation vessel.
[0034] As used herein, the terms "comprising," "comprises," and
"comprise" are open-ended transition terms used to transition from
a subject recited before the term to one or elements recited after
the term, where the element or elements listed after the transition
term are not necessarily the only elements that make up of the
subject.
[0035] As used herein, the terms "containing," "contains," and
"contain" have the same open-ended meaning as "comprising,"
"comprises," and "comprise."
[0036] As used herein, the terms "distillation" or "fractionation"
refer to the process of physically separating chemical components
into a vapor phase and a liquid phase based on differences in the
components` boiling points and vapor pressures at specified
temperature and pressure. Another type of separation may be
referred to as "phase separation," which simply allows a gas-liquid
fluid to separate based on differences in the density of the two
fluids, for example in a vessel, by releasing the fluid out of the
bottom of the vessel and releasing the gas out of the top of the
vessel without additional physical elements such as weir plates,
strippers, chimneys, internal packing, etc.
[0037] As used herein, the terms "having," "has," and "have" have
the same open-ended meaning as "comprising," "comprises," and
"comprise." As used herein, the terms "including," "includes," and
"include" have the same open-ended meaning as "comprising,"
"comprises," and "comprise."
[0038] As used herein, the term "natural gas" refers to a
multi-component gas obtained from a crude oil well (associated gas)
or from a subterranean gas-bearing formation (non-associated gas).
The composition and pressure of natural gas can vary significantly.
A typical natural gas stream contains methane (C1) as a significant
component. The natural gas stream may also contain ethane (C2),
higher molecular weight hydrocarbons, and one or more acid gases.
The natural gas may also contain minor amounts of contaminants such
as water, nitrogen, iron sulfide, wax, and crude oil.
[0039] As used herein, the term "natural gas feed stream" refers to
a stream of natural gas after it has undergone at least some
pretreatment, as described elsewhere in the disclosure.
[0040] As used herein, the term "nitrogen rejection unit" or "NRU"
refers to any system or device configured to receive a natural gas
feed stream comprising substantially methane and nitrogen and
produce substantially "pure" products streams (e.g. a salable
methane stream and a nearly pure nitrogen stream--about 96 to 99
percent N.sub.2). Examples of types of NRU's include cryogenic
distillation (most common), pressure swing adsorption (PSA),
membrane separation, lean oil absorption, and solvent
absorption.
[0041] As used herein, the term "separation unit" refers to any
vessel configured to receive a fluid having at least two
constituent elements and configured to produce a gaseous stream out
of a top portion and a liquid (or bottoms) stream out of the bottom
of the vessel. The separation unit may include internal
contact-enhancing structures (e.g. packing elements, strippers,
weir plates, chimneys, etc.), may include one, two, or more
sections (e.g. a stripping section and a reboiler section), and may
include additional inlets and outlets. Exemplary vessels include
bulk fractionators, strippers, phase separators, and others.
[0042] As used herein, the term "cryogenic condition" refers to a
temperature and pressure that is sufficient to liquefy a majority
portion of a fluid. For a fluid containing a single component, the
cryogenic condition is below the bubble point of the single
component fluid. For a fluid having multiple components, the
temperature and pressure may be below the bubble point of only one
of the components and if the composition is such that the majority
portion of the fluid is liquefied, then the fluid is under
cryogenic conditions for purposes of the present disclosure.
[0043] As used herein, the term "heat exchanger" refers to any
device or system configured to transfer heat energy or cold energy
between at least two distinct fluids. Exemplary heat exchanger
types include a co-current or counter-current heat exchanger, an
indirect heat exchanger (e.g. a spiral wound heat exchanger or a
plate-fin heat exchanger such as a brazed aluminum plate fin type),
direct contact heat exchanger, shell-and-tube heat exchanger, or
some combination of these.
Description
[0044] The disclosed systems generally disclose a rough
pre-separation of a natural gas feed stream comprising nitrogen and
methane and having a temperature above cryogenic conditions. The
systems further include a feed stream heat exchanger configured to
reduce the temperature of the natural gas feed stream to form a
substantially liquefied natural gas feed stream, a separation unit
configured to receive the cooled natural gas feed stream and
produce an overhead stream enriched in nitrogen and a bottoms
stream enriched in methane ("liquefied methane stream"), and a
liquid methane pump configured to pump the liquefied methane stream
to a gas sales compression pressure to form a pressurized liquefied
methane stream, wherein the pressurized liquefied methane stream is
substantially vaporized in the feed stream heat exchanger to form a
methane product stream.
[0045] The disclosed methods generally include the steps of cooling
a natural gas feed stream in a feed stream heat exchanger to form a
substantially liquefied natural gas feed stream, separating the
substantially liquefied natural gas feed stream in a separator to
produce an overhead stream enriched in nitrogen and a liquid
bottoms stream enriched in methane ("liquefied methane stream"),
pressurizing the liquefied methane stream in a liquid methane pump
to a gas sales compression pressure to form a pressurized liquefied
methane stream, and exchanging heat from the natural gas feed
stream to the pressurized liquefied methane stream in the feed
stream heat exchanger to form a methane product stream.
[0046] The presently disclosed systems and methods generally
disclose pre-separation of a natural gas feed stream to produce a
saleable methane product stream and a nitrogen enriched stream
still containing a significant amount of methane (e.g. from about 8
to about 40 percent nitrogen by volume with the remainder
substantially comprising methane). The produced overhead stream
enriched in nitrogen will be about 25 percent to less than 50
percent of the volume of the initial natural gas feed stream, and
may then be sent to a traditional NRU to provide additional methane
product. The pre-separation step further includes the use of a
unique LNG pump to pump the liquefied methane stream up to pressure
to provide a pressurized liquefied methane stream for heat exchange
with the natural gas feed stream, where the pressurized liquefied
methane stream is expanded into gaseous form and provided at high
pressure and preferably without additional compression to the
methane sales pipeline as a methane product stream.
[0047] In some embodiments of the systems and methods, the liquid
methane pump may be a sleeve bearing type pump and may further
include a magnetic thrust bearing to reduce a gravity thrust load
on an axial bearing of the liquid methane pump. The separation unit
may be a cryogenic separator or include a cryogenic nitrogen
stripper (a staged separation device) top portion and a reboiler
bottom portion. The overhead stream enriched in nitrogen may be
sent to a traditional nitrogen rejection unit for additional
nitrogen removal to form another methane product stream or it may
be sent to a power generation unit to produce power, or some
combination of both of these.
[0048] The described systems and methods can operate on any gas
stream containing 5% to 25% (vol) nitrogen to remove up to 75% or
more of the methane in the natural gas feed stream as a methane
product stream requiring no further processing (e.g. ready for
sale). The heat integration of the natural gas feed stream, the
pressurized liquefied methane stream, and the overhead stream
enriched in nitrogen have been carefully designed to optimize the
pressure to which the liquefied methane stream can be pumped, in
order to minimize the gas compression power needed to put the
methane product stream into a sales pipeline. The pumping power
requirement per unit of liquid methane is much less than the
compression power requirement per unit of gaseous methane.
Beneficial results of the disclosed systems and methods include
greater equipment reliability, lower capital cost, lower operating
cost, and smaller equipment footprint. In addition, the size of the
NRU (Nitrogen Removal Unit) required to treat the remaining gas is
significantly reduced. Many different commercially available NRU
designs can be employed downstream of the cryogenic bulk Nitrogen
separation process above to separate the Nitrogen from the
remaining gas stream. These and other embodiments are further
described in the attached figures, which are provided for
illustrative purposes.
[0049] Referring now to the figures, FIG. 1 is a schematic
illustration of a system in accordance with certain elements of the
disclosure. The system 100 includes a natural gas feed stream 102,
a feed stream heat exchanger 104 having a feed condensing pass 103,
a substantially liquefied natural gas feed stream 106, a flow
control element 108, a separation unit 110, a liquefied methane
stream 112, a liquid methane pump 114, a pressurized liquefied
methane stream 116, a methane product stream 118, and an overhead
stream enriched in nitrogen 120. As shown, the pressurized
liquefied methane stream 116 and the overhead stream enriched in
nitrogen 120 are routed through the feed stream heat exchanger 104,
where the pressurized liquefied methane stream 116 is vaporized to
form a methane product stream 118 and the overhead stream enriched
in nitrogen is warmed to form a warmed nitrogen enriched stream
122.
[0050] Additional elements shown in FIG. 1 include a diverted
warmed nitrogen enriched stream 124 going to a compressor 126 and a
compressed warmed nitrogen enriched stream 128 entering a nitrogen
rejection unit (NRU) 130 to form another methane product stream
132. Alternatively or in addition, another diverted warmed nitrogen
enriched stream 134 is shown going to a power generation unit
136.
[0051] The natural gas feed stream 102 is a natural gas stream that
has probably undergone pretreatment to remove some of the
contaminants and components from the natural gas stream.
Pretreatment is generally the first consideration in cryogenic
processing of natural gas. A raw natural gas suitable for the
disclosed system 100 may comprise natural gas obtained from a crude
oil well (associated gas) or from a gas well (non-associated gas).
The composition of the natural gas can vary significantly depending
on the source. Natural gas will typically contain methane (C.sub.1)
as the major component, and will typically also contain ethane
(C.sub.2), propane (C.sub.3), and other higher hydrocarbons,
diluents such as nitrogen, argon, and helium, and contaminants such
as water, carbon dioxide, mercury, mercaptans, hydrogen sulfide,
benzene, methanol, iron sulfide, ethylene glycol, and others. The
solubilities of these contaminants vary with temperature, pressure,
and composition. At cryogenic conditions, CO.sub.2, water, and
other contaminants can form solids, which can plug flow passages in
cryogenic heat exchangers and other equipment. These potential
difficulties can be avoided by removing such contaminants. Although
requirements may vary, the following are exemplary amounts of
contaminants that may be accepted in a methane product stream:
water--0.1 part per million (ppm); carbon dioxide--10 to 1,000 ppm;
methanol--1.0 ppm; benzene--0.1 ppm; hydrogen sulfide--50 to 500
ppm; ethylene glycol--1.0 ppm. In the following description, it is
assumed that the natural gas feed stream 102 has been suitably
treated to remove unacceptable levels of mercury, sulfides, carbon
dioxide, and other contaminates, and dried to remove water using
conventional and well-known processes (e.g. amine treating,
membrane separation, adsorption, etc.) to produce a "sweet, dry"
natural gas feed stream 102. Alternatively, some level of these
contaminants may be left in the natural gas feed stream 102 and
become distributed into the methane product stream which may
require additional treatment at a later stage depending on the
intended use of the methane product stream.
[0052] Although feed stream heat exchanger 104 is depicted as
surrounding the separation unit 110, the heat exchanger 104 may not
enclose the separation unit 110, but the system 100 may include a
"cold box" (an insulation system comprising a sheet metal box
filled with perlite or other appropriate insulating medium)
configured to enclose the heat exchanger 104 and the separation
unit 110. The feed exchanger 104 is configured to include a feed
condensing pass 103 configured to condense at least a majority
portion of the natural gas feed stream 102. The feed exchanger 104
is further configured to operate at pressures up to about 1,000
pounds per square inch (psi) and lower the temperature of the feed
stream 102 to a temperature of from about -180.degree. F. to about
-100.degree. F. Note that this temperature range is higher than the
temperatures generally required for full cryogenic separation of
the type that occurs in a standard cryogenic separation NRU. In
some embodiments, the heat exchanger 104 is preferably an indirect
heat exchanger such as a spiral wound heat exchanger, a plate-fin
heat exchanger (e.g. a brazed aluminum plate fin type), or a
printed circuit heat exchanger.
[0053] The substantially liquefied natural gas feed stream 106
produced from the heat exchanger 104 will preferably comprise from
about 5 volume percent (vol %) to about 25 vol % nitrogen with the
remainder being primarily methane. In addition, the natural gas
feed stream 106 may have an expected flow rate of from at least
about 10 million standard cubic feet per day (10 Mscf/d) to about
800 Mscf/d or more (larger amounts may require multiple systems 100
in parallel) and enter the system 100 at a pressure of from about
300 psi to about 1,000 psi.
[0054] Flow regulating device 108 can be any device or group of
devices capable of regulating the flow of liquid to the separation
unit 110 to maintain a desired pressure, temperature, and liquid
level in the separation unit 110, such as, but not limited to, a
flow control valve, a temperature control valve, a feed separator,
a liquid regulator, an expansion device, a flow regulating pump, or
a combination of such equipment. If the pressure of stream 106 is
higher than the pressure in the separation unit 110, the flow
regulating device 108 can be used to depressurize the liquid to a
pressure at or near the pressure of the separation unit 110. If the
pressure of the stream 106 is lower than the pressure in separation
unit 110, a flow regulating pump may be used to increase the
pressure of stream 106 to a pressure at or near the pressure of the
separation unit 110.
[0055] The separation unit 110 may be a simple phase separator
device, a bulk fractionator (e.g. distillation) type of device, a
stripper column, or some combination of these. The separation unit
110 is considered a cryogenic separation unit because it will
receive a majority liquefied natural gas feed stream 106 and
produce a liquefied methane stream 112. In one exemplary
embodiment, the separation unit 110 may be a simple cryogenic phase
separator, a cryogenic stripper column having stripping internals
such as weir plates, a cryogenic distillation column (also referred
to as a bulk fractionation column or tower) having one, two, three
or more sections with internals configured to increase the amount
of contact between a falling liquid product (liquefied methane) and
a rising gaseous product (overhead stream enriched in nitrogen). In
another alternative embodiment, the separation unit 110 may include
one inlet or more than one inlet to receive the majority liquefied
natural gas feed stream 106. For example, in some embodiments, the
separation unit 110 may comprise an upper stripping section and a
lower reboiler section.
[0056] The separation unit 110 is configured to operate at
pressures from about 200 psi to about 500 psi or from about 250 psi
to about 300 psi. Such high pressures are typically not used in
conventional nitrogen rejection unit designs to support a salable
methane product stream. In addition, the separation unit 110 is
configured to produce the liquefied methane stream 112 having less
than about 4 volume percent (vol %) nitrogen or less than about 2
vol % or less than about 1 vol % nitrogen. The liquefied methane
stream 112 is further configured to be at a pressure from about 200
psi to about 600 psi or from about 300 psi to about 500 psi and a
temperature of from about -300 degrees Fahrenheit (.degree. F.) to
about -100.degree. F. or from about -280.degree. F. to about
-160.degree. F. These compositions, pressures, and temperatures may
be adjusted depending upon process economics, requirements of a
methane sales contract, flow rate, pressure, and composition of the
natural gas feed stream 102, and other factors that can be adjusted
for by a person of ordinary skill in the art.
[0057] In one exemplary embodiment, the separation unit 110 is
configured to produce the overhead stream enriched in nitrogen 120
having from about two times to about four times the concentration
of nitrogen in the natural gas feed stream 102, depending on the
amount of nitrogen removal required. The overhead stream enriched
in nitrogen 120 is further configured to be at a pressure from
about 100 psi to about 500 psi or from about 200 psi to about 400
psi and a temperature of from about -300 degrees Fahrenheit
(.degree. F.) to about -100.degree. F. or from about -280.degree.
F. to about -160.degree. F. These compositions, pressures, and
temperatures may be adjusted depending upon process economics,
requirements of a methane sales contract, flow rate, pressure, and
composition of the natural gas feed stream 102, and other factors
that can be adjusted for by a person of ordinary skill in the
art.
[0058] In one exemplary configuration, the separation unit 110 is
configured to provide overhead stream enriched in nitrogen 120,
which may be sent to a conventional NRU 130, a power generation
unit 136, or some combination thereof. The nitrogen to methane
ratio in the overhead stream enriched in nitrogen 120 is important
for providing adequate cryogenic reflux in the NRU 130 to ensure
high methane product recovery in the NRU 130. The separation unit
110 may also be configured to separate from the natural gas feed
stream 102 a liquefied methane stream 112 that meets sales pipeline
requirements and reduces, to the greatest extent possible, the size
of the overhead stream enriched in nitrogen 120 to the NRU 130.
Beneficially, the smaller the overhead stream enriched in nitrogen
120, the smaller the NRU 130 and its associated compression
requirements.
[0059] The liquid methane pump 114 is preferably a sleeve bearing
type pump configured to pump the liquefied methane stream 112 to a
gas sales compression pressure to form a pressurized liquefied
methane stream 116. Canned motor pumps are more fully disclosed in
U.S. Pat. No. 4,890,988, which is hereby incorporated by reference
for purposes of describing canned motor pumps. In general, a canned
motor pump includes two coaxial tubular walls defining an annular
space for the flow of a heat exchange fluid which heats or cools
the can. In addition, sleeve bearing pumps may prove to be more
reliable than the currently used roller bearing pumps. These sleeve
bearing pumps are capable of reliable long life from the radial and
axial sleeve bearings. A significant contribution to the axial
thrust bearing long life is a magnetic thrust bearing compensation
device which reduces the gravity thrust load on the axial bearing
during starting. This reduction in axial thrust load allows the
hydrodynamic thrust bearing to build the lubricant film, or lift
off quicker, reducing direct frictional contact during startup
acceleration. Operationally, the pumps will experience flow
variations from near zero to maximum (e.g. up to about 25,000
m.sup.3/day) rating during cool-down, startups and upset
conditions. Similarly, the pressures can vary from near atmospheric
to rated conditions (e.g. up to about 1,000 psi). Frequent starting
and stopping of these pumps is sometimes required based on feed gas
availability. It is believed that no prior art system incorporates
these types of pumps for LNG operations. Further, persons skilled
in the art prefer not to pump LNG at such high pressures and flow
rates due to known reliability issues with the bearings in
cryogenic pumping operations at such elevated pressures and flow
rates. See, e.g. COYLE, DAVID A., PATEL, VINOD, Processes and Pump
Services in the LNG Industry, Proceedings of the Int'l Pump Users
Symposium (2005).
[0060] The liquid methane pump 114 is preferably configured to pump
a fully liquefied or nearly fully liquefied methane stream 112 from
a pressure of from a pressure of about 200 psi to about 600 psi up
to a pipeline pressure of from about 400 psi to about 1,000 psi, at
flow rates (per pump for multiple pump systems) from at least about
1,000 m.sup.3/hr to about 5,000 m.sup.3/hr or from about 1,500
m.sup.3/hr to about 3,000 m.sup.3/hr (over a day, these rates may
be from about 10,000 m.sup.3/day to about 30,000 m.sup.3/day)
depending on the requirements of the pipeline and the methane sales
contract.
[0061] FIG. 2 is a flow chart illustrating of a process in
accordance with certain aspects of the system of FIG. 1. As such,
FIG. 2 may be best understood with reference to FIG. 1. The process
200 includes box 202 showing the step of cooling a natural gas feed
stream 102 in a feed stream heat exchanger 104 to form a
substantially liquefied natural gas feed stream 106 and box 204
showing the step of separating the substantially liquefied natural
gas feed stream 106 in a separator unit 110 to produce an overhead
stream enriched in nitrogen 120 and a liquid bottoms stream
enriched in methane ("liquefied methane stream") 112. The process
200 further includes box 206 showing the step of pressurizing the
liquefied methane stream in a liquid methane pump 114 to a gas
sales compression pressure to form a pressurized liquefied methane
stream 116 and box 208 showing the step of exchanging heat from the
natural gas feed stream 102 to the pressurized liquefied methane
stream 116 in the feed stream heat exchanger 104 to form a methane
product stream 118.
[0062] The process may further include pretreating steps (not
shown) as described in connection with the system 100. The process
200 may also include feeding at least a portion of the overhead
stream enriched in nitrogen 120 to the feed stream heat exchanger
104 to form a warmed nitrogen enriched stream 122, compressing the
warmed nitrogen enriched stream in a compressor 126 to form a
compressed nitrogen enriched stream 128, which is fed to a nitrogen
rejection unit (NRU) 130 to form a methane enriched stream 132,
which may be sold as a methane product stream.
[0063] FIGS. 3A-3C are schematics of several exemplary alternative
embodiments of the system of FIG. 1. As such, FIGS. 3A-3B may be
best understood with reference to FIG. 1. In FIG. 3A, to the extent
an element in system 300 is designated with the same reference
number as system 100, that element may be considered to be
equivalent to or substantially equivalent to the element as
described above in connection with system 100. The system 300
further includes a flow control device 302, a pressure control
device 303, a controlled flow stream 306 flowing into a feed
separator 308 configured to produce a nitrogen enriched gas stream
312 and a bottoms stream enriched in methane 310, which passes to
the separator unit 110 via a level control device 311. The
separator unit 110 is configured with a top feed stripper portion
314 and a lower cryogenic reboiler portion 316 to reduce the
nitrogen content of the liquefied methane stream 112. The system
300 further includes a reboiler stream 324 from the reboiler
portion 316 of the separation unit 110 and a slip stream 320 from
the substantially liquefied natural gas feed stream 106, wherein
the slip stream 320 and reboiler stream 324 are configured to flow
through a reboiler heat exchanger 322 configured to exchange cold
energy from the reboiler stream 324 to the slip stream 320.
Nitrogen enriched gas stream 312 is configured to combine with the
overhead stream enriched in nitrogen 120 and flow through overhead
flow control valve 326 to the heat exchanger 104.
[0064] The top feed stripper 314 and reboiler 316 are configured to
significantly increase the fraction of the methane in the natural
gas feed stream 102 that is removed to the liquefied methane stream
112. Such removal beneficially significantly reduces the size of
the NRU 130 required and further enriches the overhead stream
enriched in nitrogen 120 by combining the nitrogen enriched gas
stream 312 therewith, which increases methane recovery in the NRU
130 with less methane loop or nitrogen recycle compression.
[0065] The flow control device 302 may be a low pressure drop
temperature control valve configured to increase or decrease the
flow of the majority liquefied natural gas feed stream 106 into the
slip stream 320 depending on the actual temperature of the majority
liquefied natural gas feed stream 106 and the desired temperature
of the controlled flow stream 306. For example, if the temperature
of the controlled flow stream 306 is higher than desired, the flow
control device 302 may be adjusted to restrict flow therethrough,
which will increase the flow of the slip stream 320, which passes
through reboiler heat exchanger 322 where it is cooled by indirect
heat exchange with reboiler stream 324 and is then combined with
controlled flow stream 306. Automatic or manual control may be
utilized to control the flow rates of the various streams.
[0066] The feed separator 308 is configured to accumulate fluids
and release a gaseous enriched nitrogen stream 312 and a liquid
bottoms stream 310, which is controlled by a level control device
311. In one embodiment, the level control device 311 is a low
pressure drop valve configured to maintain a particular fluid level
in the feed separator 308 for continuous operation. Beneficially,
this arrangement provides for higher nitrogen concentrations in the
overhead stream enriched in nitrogen 120, a slightly higher methane
concentration in liquid bottoms stream 310, and a slightly lower
pressure and temperature in the separation unit 110.
[0067] The overhead flow control valve 326 may be a high pressure
drop pressure control valve configured to maintain and control the
pressure and flow rate of the overhead stream enriched in nitrogen
120.
[0068] FIG. 3B schematically illustrates an exemplary system 350,
which is a modification to the systems 100, 300 to provide
additional flow control options. As shown, gaseous enriched
nitrogen stream 312 may be controlled by pressure control valve 352
to form controlled nitrogen stream 354, which may be combined with
overhead stream enriched in nitrogen 120 to form overhead stream
356. Beneficially, such an arrangement provides greater control
over the stream 356 prior to introduction into the feed stream heat
exchanger 104 as well as controlling pressure in the feed separator
308.
[0069] FIG. 3C schematically illustrates an exemplary system 370,
which is a modification to the systems 100, 300, 350 to provide yet
more additional flow control options. In particular, system 370
shows a temperature integrated controller 372 configured to obtain
a temperature of the controlled flow stream 306 and operatively
connected to flow control device 302 and slip stream flow control
device 378. Also shown is a flow integrated controller 374
configured to obtain a pressure of the majority liquefied natural
gas stream 106 and operatively connected to at least flow control
valve 376. Note, the pressure integrated controller 374 may also
control the level control device 311 and the back-pressure control
valve 352. Optionally, a feed pressure controller 382 and feed flow
controller 384 may be provided.
[0070] Beneficially, the temperature integrated controller 372 may
be configured to provide a more finely tuned temperature control of
the controlled flow stream 306 by operating temperature control
valves 302 and 378 in concert depending on the actual temperature
of the majority liquefied natural gas feed stream 106 and the
desired temperature of the controlled flow stream 306.
[0071] Still referring to FIG. 3C, the system 370 may be configured
to flow-control the majority liquefied natural gas feed stream 106
downstream of the feed stream heat exchanger 104 using either the
flow control device 376 or the level control device 311 or a
combination of these to hold the design back-pressure on the feed
condensing pass 103 of the feed stream heat exchanger 104. In
particular, the flow integrated controller 374 can be used to
override the flow control device 376 output in order to maintain
the desired minimum back-pressure in the feed condensing pass 103
of the feed stream heat exchanger 104. Note that pressure and flow
readings may be taken at stream 102, such as by a pressure sensing
device sending information to feed pressure controller 382 to
establish a set-point, which may be sent to feed flow controller
384, which may additionally obtain flow readings from a flowmeter
or other sensor to provide a set-point to the flow control device
376. Alternatively or additionally, readings may also be taken from
stream 106 and used to set the flow control device 376. The flow
integrated controller 374 can operate in cascade mode or in
automatic flow control mode, which is often used during cooldown
and startup or during turndown (low feed flow) operation. In this
mode of operation, the level control device 311 is a low pressure
drop valve, and the back-pressure on the feed separator 308 and
separation unit 110 can be controlled with a common low-pressure
drop control valve.
[0072] In another exemplary alternative embodiment, the system 370
can operate without the feed separator 308, level control device
311, and back-pressure control valve 352. In such an arrangement,
the pressure control functions are all accomplished using the flow
control device 376, which is a high pressure drop expansion valve,
such as a Joule-Thompson type unit.
[0073] The flow control device 376 can also be configured to
operate independently of the pressure control function by using the
back-pressure control valve 352 to increase the operating pressure
of the feed separator 308 and using level control device 311 as the
primary liquid expansion device (e.g. a Joule-Thompson type valve).
Note that the back-pressure control valve 352 would operate as a
vapor expansion device in this case. In this embodiment, the top
feed separator 308 is provided, and the feed separator 308 operates
at the same pressure as the feed condensing pass 103 in the feed
exchanger 104. The temperature control valve 302 is a low pressure
drop valve and the feed separator back pressure control 352 and
level control valve 311 are both high pressure drop valves. As
such, at least part of the feed expansion device operation takes
place across these two separator control valves.
[0074] FIG. 4 illustrates a chart showing a temperature heat flow
plot for comparing heat flow between hot and cold streams. The
chart 400 plots temperature in degrees Fahrenheit (.degree. F.)
along the y-axis 402 and heat flow in millions of British thermal
units per hour (MBtu/hr) along the x-axis 404. A curve for a warm
fluid (about 900 psi) flowing through a heat exchanger is shown at
406, a curve for a lower pressure (about 300 psi) cold fluid
flowing through the heat exchanger is shown at 408, and a curve for
a higher pressure (about 775 psi) cold fluid flowing through the
heat exchanger is shown at 410. In T-Q charts such as chart 400,
the important factor is the gap between the warm fluid curve 406
and the cold fluid curves 408 or 410. As shown, the gap between the
warm fluid curve 406 and the high pressure cold fluid curve 410
maintains about a 5-10 degree difference through the charted
temperature range of about -130.degree. F. to about 130.degree. F.
This means that there is heat transfer between these two fluids,
even at the higher pressures. There is a slightly higher rate of
heat transfer between the warm fluid 406 and the lower pressure
cold fluid 408 than between the warm fluid 406 and the high
pressure cold fluid 410, but for the purposes of the disclosure,
the heat transfer is sufficient to meet the requirements of the
process.
[0075] Beneficially, keeping the fluid at a higher pressure reduces
or eliminates the need to repressurize the product gas for pipeline
delivery, which eliminates a portion of the horsepower, footprint,
and materials needed for compression of the lower pressure stream.
This process efficiency more than makes up for the slight decrease
in heat transfer efficiency shown by the T-Q chart 400.
EXAMPLE
[0076] In one exemplary case, a natural gas feed stream having an
assumed temperature, flow rate, pressure, and composition was
provided. Table 1 below shows the temperature, flow rate, pressure,
and composition of the relevant streams as shown in FIGS. 1 and
3A.
TABLE-US-00001 TABLE 1 Stream Stream Stream Stream Stream Stream
Stream Stream Component 102 122 118 106 306 112 120 312 methane
0.904 0.775 0.977 0.904 0.904 0.965 0.781 0.773 nitrogen 0.093
0.224 0.020 0.093 0.093 0.032 0.219 0.227 ethane 0.003 0.001 0.003
0.003 0.003 0.003 0.000 0.000 Total 1.000 1.000 1.000 1.000 1.000
1.000 1.000 1.000 Pressure 915 275 770 905 902 285 280 300 (psia)
Temperature 136 130 130 -131 -150 -170 -176 -174 (deg F.) Mscfd 95
34 61 95 95 77 16 18
[0077] In particular, the exemplary flow rates illustrate the
relative size of warmed nitrogen rich stream 122 as compared with
the natural gas feed stream 102. Beneficially, this results in a
smaller volume of fluids going to the NRU 130 for further
treatment, lowering the energy consumption, footprint, materials,
and capital costs of such systems and methods as disclosed herein.
It is also worth noting the difference in pressure between stream
112 and 118. This pressure increase is preferably obtained through
pumping stream 112 up to pressure rather than using compression
equipment, which provides still more savings in energy use and
equipment cost as well as potentially providing greater
reliability.
[0078] While the present disclosure may be susceptible to various
modifications and alternative forms, the exemplary embodiments
discussed above have been shown only by way of example. However, it
should again be understood that the disclosure is not intended to
be limited to the particular embodiments disclosed herein. Indeed,
the present disclosure includes all alternatives, modifications,
and equivalents falling within the true spirit and scope of the
appended claims.
* * * * *