U.S. patent application number 15/903745 was filed with the patent office on 2018-10-04 for hydraulic turbine between middle and cold bundles of natural gas liquefaction heat exchanger.
The applicant listed for this patent is Brian Downs, Suhas P. Mondkar, O. Angus Sites, Steve Wright. Invention is credited to Brian Downs, Suhas P. Mondkar, O. Angus Sites, Steve Wright.
Application Number | 20180283773 15/903745 |
Document ID | / |
Family ID | 61617135 |
Filed Date | 2018-10-04 |
United States Patent
Application |
20180283773 |
Kind Code |
A1 |
Mondkar; Suhas P. ; et
al. |
October 4, 2018 |
Hydraulic Turbine Between Middle and Cold Bundles of Natural Gas
Liquefaction Heat Exchanger
Abstract
A system and method for liquefying a natural gas stream,
including a liquefaction heat exchanger having at least three
cooling bundles and arranged such that the natural gas stream
passes sequentially therethrough. A first cooling bundle condenses
heavy hydrocarbon components in the natural gas stream. A second
cooling bundle liquefies the natural gas stream. A third cooling
bundle sub-cools the LNG stream. A hydraulic turbine has an inlet
operationally connected to an outlet of the second cooling bundle,
and an outlet operationally connected to an inlet of the third
cooling bundle. The hydraulic turbine cools the LNG stream and
reduces the pressure of the LNG stream to form a reduced-pressure
LNG stream.
Inventors: |
Mondkar; Suhas P.; (Houston,
TX) ; Sites; O. Angus; (Spring, TX) ; Wright;
Steve; (Georgetown, TX) ; Downs; Brian;
(Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Mondkar; Suhas P.
Sites; O. Angus
Wright; Steve
Downs; Brian |
Houston
Spring
Georgetown
Houston |
TX
TX
TX
TX |
US
US
US
US |
|
|
Family ID: |
61617135 |
Appl. No.: |
15/903745 |
Filed: |
February 23, 2018 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
62479880 |
Mar 31, 2017 |
|
|
|
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
F25J 2230/20 20130101;
F25J 1/0062 20130101; F25J 1/0244 20130101; F25J 1/0042 20130101;
F25J 2215/04 20130101; F25J 1/0082 20130101; F25J 2240/30 20130101;
F25J 1/0055 20130101; F25J 1/0221 20130101; F25J 1/0022 20130101;
F25J 2240/04 20130101; F25J 1/0274 20130101; F25J 2240/40 20130101;
F25J 1/0257 20130101 |
International
Class: |
F25J 1/00 20060101
F25J001/00; F25J 1/02 20060101 F25J001/02 |
Claims
1. A system for liquefying a natural gas stream, comprising: a
liquefaction heat exchanger having at least three cooling bundles
and arranged such that the natural gas stream passes sequentially
therethrough, including a first cooling bundle configured to
condense heavy hydrocarbon components in the natural gas stream, a
second cooling bundle configured to liquefy the natural gas stream,
the second cooling bundle having an outlet for passing an LNG
stream therethrough, and a third cooling bundle having an inlet to
receive the LNG, the third cooling bundle configured to sub-cool
the LNG stream; and a hydraulic turbine having an inlet
operationally connected to the outlet of the second cooling bundle
and an outlet operationally connected to the inlet of the third
cooling bundle, the hydraulic turbine configured to cool the LNG
stream and reduce a pressure of the LNG stream to form a
reduced-pressure LNG stream.
2. The system of claim 1, further comprising: a first set of one or
more sensors situated to sense at least one of a pressure and a
temperature of the LNG stream prior to entering the hydraulic
turbine; and a second set of one or more sensors situated to sense
at least one of a pressure and a temperature of the LNG stream as
the LNG stream exits the hydraulic turbine.
3. The system of claim 2, wherein at least one of a) a speed of the
hydraulic turbine and b) an LNG inlet flow rate to the hydraulic
turbine is adjusted based on at least one of the sensed temperature
of the LNG stream prior to entering the hydraulic turbine, the
sensed pressure of the LNG stream prior to entering the hydraulic
turbine, the sensed temperature of the LNG stream as the LNG stream
exits the hydraulic turbine, and the sensed pressure of the LNG
stream as the LNG stream exits the hydraulic turbine.
4. The system of claim 2, further comprising a bypass valve
operationally connecting the outlet of the second cooling bundle
and the inlet of the third cooling bundle such that, when open, at
least a portion of the LNG stream bypasses the hydraulic
turbine.
5. The system of claim 4, wherein the bypass valve is selectively
controlled based on at least one of the sensed temperature of the
LNG stream prior to entering the hydraulic turbine, the sensed
pressure of the LNG stream prior to entering the hydraulic turbine,
the sensed temperature of the LNG stream as the LNG stream exits
the hydraulic turbine, and the sensed pressure of the LNG stream as
the LNG stream exits the hydraulic turbine.
6. The system of claim 1, further comprising a control valve
disposed between the outlet of the hydraulic turbine and the inlet
of the third cooling bundle, wherein the control valve is
selectively controlled based at least in part on one or more of a
sensed temperature of the LNG stream prior to entering the
hydraulic turbine, a sensed pressure of the LNG stream prior to
entering the hydraulic turbine, a sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and a sensed
pressure of the LNG stream as the LNG stream exits the hydraulic
turbine.
7. The system of claim 1, further comprising a generator connected
to the hydraulic turbine and configured to generate power based on
the work energy generated by the hydraulic turbine.
8. The system of claim 7, further comprising: a first set of one or
more sensors situated to sense at least one of a pressure and a
temperature of the LNG stream prior to entering the hydraulic
turbine, and a second set of one or more sensors situated to sense
at least one of a pressure and a temperature of the LNG stream as
the LNG stream exits the hydraulic turbine; wherein a speed of the
generator is adjusted based on at least one of the sensed
temperature of the LNG stream prior to entering the hydraulic
turbine, the sensed pressure of the LNG stream prior to entering
the hydraulic turbine, the sensed temperature of the LNG stream as
the LNG stream exits the hydraulic turbine, and the sensed pressure
of the LNG stream as the LNG stream exits the hydraulic
turbine.
9. The system of claim 7, further comprising a variable-speed
constant-frequency (VSCF) drive situated between the generator and
a power system, wherein the VSCF drive is selectively controlled
based at least in part on one or more of the sensed temperature of
the LNG stream prior to entering the hydraulic turbine, the sensed
pressure of the LNG stream prior to entering the hydraulic turbine,
the sensed temperature of the LNG stream as the LNG stream exits
the hydraulic turbine, the sensed pressure of the LNG stream as the
LNG stream exits the hydraulic turbine and the power system
frequency.
10. The system of claim 1, further comprising at least one of a
mechanical brake and a compressor operationally connected to the
hydraulic turbine.
11. The system of claim 10, wherein the brake is selectively
controlled based at least in part on one or more of a sensed
temperature of the LNG stream prior to entering the hydraulic
turbine, a sensed pressure of the LNG stream prior to entering the
hydraulic turbine, a sensed temperature of the LNG stream as the
LNG stream exits the hydraulic turbine, and a sensed pressure of
the LNG stream as the LNG stream exits the hydraulic turbine.
12. The system of claim 1, further comprising: a liquefied
petroleum gas (LPG) stream configured to pass through the first
cooling bundle and the second cooling bundle, the reduced-pressure
LNG stream being at a pressure so to as to be combined with the LPG
stream after the LPG stream has passed through the second cooling
bundle.
13. A method of liquefying a natural gas stream to produce
liquefied natural gas (LNG), comprising: sequentially cooling the
natural gas stream in first, second, and third cooling bundles of a
liquefaction heat exchanger, wherein the second cooling bundle
liquefies the natural gas stream to produce an LNG stream; cooling
and reducing the pressure of the LNG stream between the second
cooling bundle and the third cooling bundle using a hydraulic
turbine, to thereby produce a reduced-pressure LNG stream; and
producing work energy using the hydraulic turbine.
14. The method of claim 13, further comprising: adjusting at least
one of a) a speed of the hydraulic turbine and b) an LNG inlet rate
of the hydraulic turbine based on at least one of a sensed
temperature of the LNG stream prior to entering the hydraulic
turbine, a sensed pressure of the LNG stream prior to entering the
hydraulic turbine, a sensed temperature of the LNG stream as the
LNG stream exits the hydraulic turbine, and a sensed pressure of
the LNG stream as the LNG stream exits the hydraulic turbine.
15. The method of claim 13, further comprising: selectively
directing at least a portion of the LNG stream exiting the
hydraulic turbine through a bypass valve that operationally
connects an outlet of the second cooling bundle and an inlet of the
third cooling bundle; and selectively controlling the bypass valve
based on at least one of a sensed temperature of the LNG stream
prior to entering the hydraulic turbine, a sensed pressure of the
LNG stream prior to entering the hydraulic turbine, a sensed
temperature of the LNG stream as the LNG stream exits the hydraulic
turbine, and a sensed pressure of the LNG stream as the LNG stream
exits the hydraulic turbine.
16. The method of claim 13, further comprising controlling a
pressure of the LNG stream exiting the hydraulic turbine by
disposing a control valve between an outlet of the hydraulic
turbine and an inlet of the third cooling bundle, wherein the
control valve is selectively controlled based at least in part on
one or more of a sensed temperature of the LNG stream prior to
entering the hydraulic turbine, a sensed pressure of the LNG stream
prior to entering the hydraulic turbine, a sensed temperature of
the LNG stream as the LNG stream exits the hydraulic turbine, and a
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine.
17. The method of claim 13, further comprising: connecting a
generator to the hydraulic turbine; and generating power using the
generator based on the work energy generated by the hydraulic
turbine.
18. The method of claim 17, further comprising: adjusting a speed
of the generator based on at least one of a sensed temperature of
the LNG stream prior to entering the hydraulic turbine, a sensed
pressure of the LNG stream prior to entering the hydraulic turbine,
a sensed temperature of the LNG stream as the LNG stream exits the
hydraulic turbine, and a sensed pressure of the LNG stream as the
LNG stream exits the hydraulic turbine.
19. The method of claim 17, further comprising: controlling an
electrical output of the generator using a variable-speed
constant-frequency drive situated between the hydraulic turbine and
the generator.
20. The method of claim 13, further comprising: operationally
connecting at least one of a mechanical brake and a compressor to
the hydraulic turbine.
21. The method of claim 13, further comprising: obtaining a
liquefied petroleum gas (LPG) stream from a fractionation process
that occurs prior to the natural gas stream being sequentially
cooled in the liquefaction heat exchanger; cooling the LPG stream
in the first cooling bundle and the second cooling bundle, the
reduced-pressure LNG stream being at a pressure so as to be
combined with the LPG stream after the LPG stream has passed
through the second cooling bundle.
22. The method of claim 21, wherein the liquefaction heat exchanger
is part of an operating LNG process, and further comprising:
retrofitting the hydraulic turbine between the second cooling
bundle and the third cooling bundle.
23. A method of liquefying a natural gas stream to produce
liquefied natural gas (LNG), comprising: sequentially cooling the
natural gas stream in a liquefaction heat exchanger having first,
second, and third cooling bundles, wherein the second cooling
bundle liquefies the natural gas stream to produce an LNG stream;
cooling and reducing the pressure of the LNG stream between the
second cooling bundle and the third cooling bundle using a
hydraulic turbine; producing work energy using the hydraulic
turbine; using the work energy, generating power using a generator
connected to the hydraulic turbine; controlling a pressure of the
LNG stream exiting the hydraulic turbine using a control valve
disposed between the outlet of the hydraulic turbine and an inlet
of the third cooling bundle; and adjusting at least one of a speed
of the hydraulic turbine, an LNG inlet rate of the hydraulic
turbine, a position of the control valve, and a speed of the
generator, based on at least one of a sensed temperature of the LNG
stream prior to entering the hydraulic turbine, a sensed pressure
of the LNG stream prior to entering the hydraulic turbine, a sensed
temperature of the LNG stream as the LNG stream exits the hydraulic
turbine, and a sensed pressure of the LNG stream as the LNG stream
exits the hydraulic turbine.
24. The method of claim 23, further comprising: when the hydraulic
turbine is desired to be bypassed, selectively directing at least a
portion of the LNG stream exiting the middle bundle through a
bypass valve that operationally connects an outlet of the second
cooling bundle and an inlet of the third cooling bundle; and
adjusting a position of the bypass valve based on at least one of
the sensed temperature of the LNG stream prior to entering the
hydraulic turbine, the sensed pressure of the LNG stream prior to
entering the hydraulic turbine, the sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and the
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] This application claims the priority benefit of U.S. Patent
Application 62/479,880 filed Mar. 31, 2017 entitled HYDRAULIC
TURBINE BETWEEN MIDDLE AND COLD BUNDLES OF NATURAL GAS LIQUEFACTION
HEAT EXCHANGER, the entirety of which is incorporated by reference
herein.
FIELD
[0002] The disclosure relates to the liquefaction of natural gas to
form liquefied natural gas (LNG), and more specifically, to
improving efficiencies in an LNG-producing heat exchanger.
BACKGROUND
[0003] LNG production is a rapidly growing means to supply natural
gas from locations with an abundant supply of natural gas to
distant markets having a strong demand for natural gas. The
conventional LNG cycle includes: a) initial treatments of the
natural gas resource to remove contaminants such as water, sulfur
compounds and carbon dioxide; b) separating some heavier
hydrocarbon gases, such as propane, butane, pentane, etc. by a
variety of possible methods including self-refrigeration, external
refrigeration, lean oil, etc.; c) refrigerating the natural gas
substantially by external refrigeration to form LNG at near
atmospheric pressure and about -160.degree. C.; d) transporting the
LNG product in ships or tankers designed for this purpose to a
market location; e) re-pressurizing and re-gasifying the LNG to
form a pressurized natural gas that may distributed in a natural
gas distribution system.
[0004] The liquefaction of step c) may be accomplished using
indirect heat exchange with a refrigerant in a cryogenic heat
exchanger. Such a cryogenic heat exchanger may include multiple
heat exchange bundles to progressively cool a natural gas stream so
the natural gas stream is eventually liquefied and sub-cooled.
Traditionally, Joule-Thomson (JT) valves have been used to control
pressures and temperatures in the bundles via isenthalpic pressure
reduction. While inexpensive, JT valves provide a limited cooling
effect and do not recover power from the process stream. What is
needed is a method of increasing the cooling effect inside a
cryogenic LNG heat exchanger. What is also needed is a method of
increasing throughput of an LNG process.
[0005] Hydraulic turbines achieve process control objectives
(temperature/pressure), reach lower discharge temperatures, and
extract power associated with pressure reduction. The thermodynamic
basis for a hydraulic turbine (hydraulic expander, expander) is a
near-isentropic expansion of a liquid process fluid, through which
the temperature of the process fluid is reduced and mechanical
shaft work is generated. U.S. Pat. No. 4,334,902 to Paradowski
describes a method of sub-cooling a natural gas stream via
expansion in the liquid condition, with a hydraulic turbine
providing mechanical power possibly for driving a rotary machine.
Others have since employed applications of expander technology to
refrigeration and liquefaction processes. Design and application of
expander technology is generally well understood, and considered
standard for latest generation process designs. Typical natural gas
liquefaction processes apply hydraulic turbines in the expansion of
the final LNG condensate and in the expansion of liquid coolant in
the refrigeration cycle. However, the use of hydraulic turbine
expanders to expand and cool a process gas stream within an LNG
cryogenic heat exchanger has not been suggested.
SUMMARY
[0006] The disclosed aspects provide a system for liquefying a
natural gas stream. A liquefaction heat exchanger has at least
three cooling bundles and is arranged such that the natural gas
stream passes sequentially therethrough. A first cooling bundle is
configured to condense heavy hydrocarbon components in the natural
gas stream. A second cooling bundle is configured to liquefy the
natural gas stream. The second cooling bundle has an outlet for
passing an LNG stream therethrough. A third cooling bundle has an
inlet to receive the LNG. The third cooling bundle is configured to
sub-cool the LNG stream. A hydraulic turbine has an inlet
operationally connected to the outlet of the second cooling bundle
and an outlet operationally connected to the inlet of the third
cooling bundle. The hydraulic turbine is configured to cool the LNG
stream and reduce a pressure of the LNG stream to form a
reduced-pressure LNG stream.
[0007] The disclosed aspects also provide a method of liquefying a
natural gas stream to produce liquefied natural gas (LNG). The
natural gas stream is sequentially cooled in first, second, and
third cooling bundles of a liquefaction heat exchanger. The second
cooling bundle liquefies the natural gas stream to produce an LNG
stream. The LNG stream is cooled and its pressure is reduced
between the second cooling bundle and the third cooling bundle
using a hydraulic turbine, to thereby produce a reduced-pressure
LNG stream. Work energy is produced using the hydraulic
turbine.
[0008] The disclosed aspects also provide a method of liquefying a
natural gas stream to produce liquefied natural gas (LNG). The
natural gas stream is sequentially cooled in a liquefaction heat
exchanger having first, second, and third cooling bundles. The
second cooling bundle liquefies the natural gas stream to produce
an LNG stream. The LNG stream is cooled and its pressure is reduced
between the second cooling bundle and the third cooling bundle
using a hydraulic turbine. Work energy is produced using the
hydraulic turbine. Using the work energy, power is generated using
a generator connected to the hydraulic turbine. The pressure of the
LNG stream exiting the hydraulic turbine is controlled using a
control valve disposed between the outlet of the hydraulic turbine
and an inlet of the third cooling bundle. The method adjusts at
least one of a speed of the hydraulic turbine, an LNG inlet rate of
the hydraulic turbine, a position of the control valve, and a speed
of the generator, based on at least one of a sensed temperature of
the LNG stream prior to entering the hydraulic turbine, a sensed
pressure of the LNG stream prior to entering the hydraulic turbine,
a sensed temperature of the LNG stream as the LNG stream exits the
hydraulic turbine, and a sensed pressure of the LNG stream as the
LNG stream exits the hydraulic turbine.
BRIEF DESCRIPTION OF THE FIGURES
[0009] FIG. 1 is a schematic diagram of an LNG liquefaction
process;
[0010] FIG. 2 is a simplified plan view of a main cryogenic LNG
heat exchanger according to known principles;
[0011] FIG. 3 is a simplified plan view of a main cryogenic LNG
heat exchanger according to disclosed aspects;
[0012] FIG. 4 is a simplified schematic of a hydraulic turbine
according to disclosed aspects;
[0013] FIG. 5 is a simplified schematic of a hydraulic turbine
according to disclosed aspects;
[0014] FIG. 6 is a simplified schematic of a hydraulic turbine
according to disclosed aspects;
[0015] FIG. 7 is a simplified schematic of a hydraulic turbine
according to disclosed aspects;
[0016] FIG. 8 is a flowchart of a method according to disclosed
aspects; and
[0017] FIG. 9 is a flowchart of a method according to disclosed
aspects.
DETAILED DESCRIPTION
[0018] Various specific aspects and versions of the present
disclosure will now be described, including preferred aspects and
definitions that are adopted herein. While the following detailed
description gives specific preferred aspects, those skilled in the
art will appreciate that these aspects are exemplary only, and that
the present techniques can be practiced in other ways. Any
reference to the "invention" or "aspect" may refer to one or more,
but not necessarily all, of the aspects defined by the claims. The
use of headings is for purposes of convenience only and does not
limit the scope of the present techniques. For purposes of clarity
and brevity, similar reference numbers in the several Figures
represent similar items, steps, or structures and may not be
described in detail in every Figure.
[0019] All numerical values within the detailed description and the
claims herein are modified by "about" or "approximately" the
indicated value, and take into account experimental error and
variations that would be expected by a person having ordinary skill
in the art. Certain aspects and features have been described using
a set of numerical upper limits and a set of numerical lower
limits. It should be appreciated that ranges from any lower limit
to any upper limit are contemplated unless otherwise indicated.
[0020] The term "gas" is used interchangeably with "vapor," and
means a substance or mixture of substances in the gaseous state as
distinguished from the liquid or solid state. Likewise, the term
"liquid" means a substance or mixture of substances in the liquid
state as distinguished from the gas or solid state. As used herein,
"fluid" is a generic term that may include either a gas or
liquid.
[0021] A "hydrocarbon" is an organic compound that primarily
includes the elements hydrogen and carbon although nitrogen,
sulfur, oxygen, metals, or any number of other elements may be
present in small amounts. As used herein, hydrocarbons generally
refer to organic materials, such as any form of natural gas or oil.
A "hydrocarbon stream" is a stream enriched in hydrocarbons.
[0022] "Pressure" is the force exerted per unit area by the gas on
the walls of the volume. Pressure can be shown as pounds per square
inch (psi). "Atmospheric pressure" refers to the local pressure of
the air. "Absolute pressure" (psia) refers to the sum of the
atmospheric pressure (14.7 psia at standard conditions) plus the
gauge pressure (psig). "Gauge pressure" (psig) refers to the
pressure measured by a gauge, which indicates only the pressure
exceeding the local atmospheric pressure (i.e., a gauge pressure of
0 psig corresponds to an absolute pressure of 14.7 psia).
[0023] "Substantial" when used in reference to a quantity or amount
of a material, or a specific characteristic thereof, refers to an
amount that is sufficient to provide an effect that the material or
characteristic was intended to provide. The exact degree of
deviation allowable may in some cases depend on the specific
context.
[0024] "Well" refers to a hole in the subsurface made by drilling
or insertion of a conduit into the subsurface.
[0025] The term "natural gas" refers to a hydrocarbon 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 (C.sub.1) as a significant component.
Raw natural gas will also typically contain ethane (C.sub.2),
higher molecular weight hydrocarbons, one or more acid gases (such
as carbon dioxide, hydrogen sulfide, carbonyl sulfide, carbon
disulfide, and mercaptans), and contaminants such as water,
nitrogen, iron sulfide, mercury, helium, wax, and crude oil.
[0026] As used herein, the term "compressor" means a machine that
increases the pressure of a gas by the application of work. A
"compressor" includes any unit, device, or apparatus able to
increase the pressure of a gas stream. This includes compressors
having a single compression process or step, or compressors having
multi-stage compressions or steps, or more particularly multi-stage
compressors within a single casing or shell. Gaseous streams to be
compressed can be provided to a compressor at different pressures.
Some stages or steps of a cooling process may involve two or more
compressors in parallel, series, or both. The disclosed aspects are
not limited by the type or arrangement or layout of the compressor
or compressors, particularly in any refrigerant circuit.
[0027] As used herein, the term "JT valve" (also known as
Joule-Thomson valve or throttling valve) means a control valve that
substantially decreases the pressure of a fluid, including liquids,
without the removal of work (approximating an isenthalpic
throttling process). Ideally during pressure reduction through a JT
valve, the fluid is maintained at constant enthalpy, which in most
cases, is accompanied by a temperature reduction. A JT valve is
adjustable such that fluid flow rate, pressure or pressure
reduction can be controlled.
[0028] As used herein, the term "hydraulic turbine" (also known as
"liquid expander" or "dense fluid expander") means a machine that
decreases the pressure of a liquid by the removal of work
(approximating an isentropic process). Ideally during pressure
reduction through a hydraulic turbine, the liquid is maintained at
constant entropy, which in most cases, is accompanied by a
temperature reduction. For the same pressure reduction, an
isentropic process (hydraulic turbine) results in a lower outlet
temperature than an isenthalpic process (JT valve). A "hydraulic
turbine" includes any unit, device, or apparatus able to decrease
the pressure of a liquid stream and extract work. This includes
hydraulic turbines having a single pressure reduction process or
stage, or hydraulic turbines having multiple stages, or more
particularly multi-stage hydraulic turbines within a single casing
or shell. Some stages of a depressurization process may involve two
or more hydraulic turbines in parallel, series, or both. The
disclosed aspects are not limited by the type or arrangement or
layout of the hydraulic turbine or hydraulic turbines, particularly
in any LNG service.
[0029] As used herein, "cooling" broadly refers to lowering and/or
dropping a temperature and/or internal energy of a substance by any
suitable, desired, or required amount. Cooling may include a
temperature drop of at least about 1.degree. C., at least about
5.degree. C., at least about 10.degree. C., at least about
15.degree. C., at least about 25.degree. C., at least about
35.degree. C., or least about 50.degree. C., or at least about
75.degree. C., or at least about 85.degree. C., or at least about
95.degree. C., or at least about 100.degree. C., or at least about
150.degree. C., or at least about 200.degree. C., or at least about
260.degree. C. The cooling may use any suitable heat sink, such as
steam generation, hot water heating, cooling water, air,
refrigerant, other process streams (integration), and combinations
thereof. One or more sources of cooling may be combined and/or
cascaded to reach a desired outlet temperature. The cooling step
may use a cooling unit with any suitable device and/or equipment.
According to some aspects, cooling may include indirect heat
exchange, such as with one or more heat exchangers. In the
alternative, the cooling may use evaporative (heat of vaporization)
cooling and/or direct heat exchange, such as a liquid sprayed
directly into a process stream.
[0030] A "heat exchanger" broadly means any device capable of
transferring heat energy from one medium to another medium, such as
between at least two distinct fluids. Heat exchangers include
"direct heat exchangers" and "indirect heat exchangers." Thus, a
heat exchanger may be of any suitable design, such as 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, spiral, hairpin, core,
core-and-kettle, printed-circuit, double-pipe or any other type of
known heat exchanger. "Heat exchanger" may also refer to any
column, tower, unit or other arrangement adapted to allow the
passage of one or more streams therethrough, and to affect direct
or indirect heat exchange between one or more lines of refrigerant,
and one or more feed streams. A heat exchanger as disclosed herein
may include multiple heat exchangers as needed or desired.
[0031] 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 examples of equipment that facilitate indirect heat
exchange.
[0032] All patents, test procedures, and other documents cited in
this application are fully incorporated by reference to the extent
such disclosure is not inconsistent with this application and for
all jurisdictions in which such incorporation is permitted.
[0033] Described herein are methods and systems for liquefying a
natural gas stream to form liquefied natural gas (LNG). The
described methods and systems use a hydraulic turbine to cool and
reduce the pressure of an LNG stream within a liquefaction heat
exchanger. The hydraulic turbine may be coupled to an electrical
generator or a brake. The brake dissipates the work, extracted from
the liquid, to the environment. The electric generator uses the
work, extracted from the liquid, to generate electricity. The
electricity from an electric generator may be processed by a
variable speed constant frequency (VSCF) drive or machine that will
allow the speed of hydraulic turbine to be adjustable. The
adjustable speed of the hydraulic turbine allows some control over
fluid flow rate, pressure or pressure reduction.
[0034] Specific aspects of the disclosure include those set forth
in the following paragraphs as described with reference to the
Figures. While some features are described with particular
reference to only one Figure, they may be equally applicable to the
other Figures and may be used in combination with the other Figures
or the foregoing discussion.
[0035] FIG. 1 is a schematic diagram showing the basic steps in a
typical natural gas liquefaction process 100. The process 100 is a
simplified rendition of a liquefaction process, it being understood
that an actual liquefaction process may add, subtract, or replace
one or more steps disclosed herein. The feedstock gas 102 to the
process 100 comprises mostly light hydrocarbons, and may be a raw
feed gas directly transported from one or more wells.
Alternatively, the feedstock may be gas from a pipeline that has
been partially conditioned to be suitable for such transport. The
feedstock gas may contain free liquid, mercury, acid gases, such as
carbon dioxide and hydrogen sulfide, water, and other sulfur
species. The gas must be treated to remove these contaminants and
thoroughly dried before it can be converted to LNG. The process 100
shows typical steps for this treating and dehydration. At block 104
preliminary steps such as liquid removal, pressure control, mercury
removal, and metering are performed. At block 106 acid gases such
as carbon dioxide and hydrogen sulfide are removed. At block 108
one or more dehydration processes are performed. At this point in
process 100 the feedstock gas has been converted to a dry gas
stream 110. At block 112 the dry gas stream is pre-cooled to
condense heavy hydrocarbons and aromatics, which might freeze in
the subsequent liquefaction step. Some liquefied petroleum gases
(e.g., ethane, propane, and butane) are also condensed and
separated from the heavy hydrocarbons and aromatics in a
fractionation unit at block 114. The liquefied petroleum gases 118
are re-injected into the dry gas stream to be liquefied in the
liquefaction step at block 116, although some of the liquefied
petroleum gases may be drawn off for refrigerant make-up or sold as
LPG products. The heavy hydrocarbons and aromatics separated by the
fractionation unit 114 form a condensate product 120 that is not
liquefied in the liquefaction step.
[0036] The liquefaction step at block 116 may be performed by a
cryogenic heat exchanger that exchanges heat between the dry gas
stream 110 and a refrigerant 122 so that the dry gas stream is
liquefied, thereby producing a liquefied natural gas (LNG) stream
124. The refrigerant may include methane, propane, nitrogen, one or
more noble gases, and/or one or more fluorocarbons. After
liquefying the dry gas stream 110, the refrigerant 122 is
refrigerated and compressed at block 126 and recycled back to the
liquefaction step at block 116 through a return line 127. At block
128 the LNG is run through a fractionation column or flash drum,
where excess nitrogen is rejected, to reduce the nitrogen content
of the LNG stream to a desired level. The nitrogen-rich gas stream
130 is typically used as a fuel stream for one or more plant
processes. At block 132 the LNG product stream 133, now at near
atmospheric pressure, is stored for transport or use.
[0037] FIG. 2 is a simplified elevation view of an exemplary known
liquefaction heat exchanger 200, which is commonly referred to as a
main cryogenic heat exchanger. Liquefaction heat exchanger 200 has
three sections of multi-pass heat exchange: a warm bundle 202, a
middle bundle 204, and a cold bundle 206. The lines identified by
reference numbers 208, 210, and 212 follow the heat exchanger cold
passes, which cool all the other passes--termed the warm passes--in
the heat exchanger. The liquefaction heat exchanger 200 may be
designed as a spiral-wound heat exchanger, in which case the warm
passes comprise bundles of small-bore tubing wound around a central
mandrel and the cold pass stream is sprayed over the bundles to
provide cooling. Alternatively, the liquefaction heat exchanger
could be a plate-fin heat exchanger, in which case the warm passes
and the cold passes are integrated into a core exchanger separated
by alternating plates. Other types of liquefaction heat exchangers
may be used as well, but for ease of explaining herein the
disclosed aspects, a spiral-wound heat exchanger design will be
described.
[0038] Referring to FIG. 2, the hydrocarbon gas to be liquefied,
which in disclosed aspects may be the dry gas stream 110 shown in
FIG. 1, enters the warm bundle 202 where it is pre-cooled to
condense heavy components, which might freeze in the colder
sections of the liquefaction heat exchanger. The warm bundle is
analogous to the precooling step 112 shown in FIG. 1. The
pre-cooled natural gas stream 214 leaves the liquefaction heat
exchanger so that condensed components such as heavy hydrocarbons
may be separated out. After separating out the condensed heavy
components, the natural gas stream returns through line 216 and
enters the middle bundle 204. The natural gas stream is condensed
in the middle bundle and leaves the middle bundle as a
high-pressure LNG stream through line 218. A gaseous or two-phase
stream of liquefied petroleum gases (LPGs) 220, which may be
generated by the fractionation step 114 of FIG. 1, is also passed
through the warm bundle 202 and the middle bundle 204 to produce a
cooled LPG stream 222. To combine the high pressure LNG stream in
line 218 with the cooled LPG stream 222, it is necessary to
let-down or reduce the pressure of the high pressure LNG stream.
According to known principles, the high-pressure LNG stream in line
218 is let-down or reduced across a Joule-Thomson (J-T) valve 224.
The J-T valve 224 operates under pressure control to achieve a
suitable downstream pressure to mix with the cooled LPG stream 222.
The combined LNG/LPG stream 226 is then sub-cooled as it passes
through the cold bundle 206, and leaves the liquefaction heat
exchanger as a medium-pressure LNG stream 228.
[0039] A light refrigerant stream 230 is cooled successively in the
warm bundle 202, the middle bundle 204, and the cold bundle 206,
and exits the cold bundle through line 231. The refrigerant in line
231 may pass through a control valve 233, which may be a J-T valve,
according to known liquefaction principles, and re-enters the cold
bundle via line 208, where it provides cooling for the cold bundle
206. A heavy refrigerant in line 232 is cooled successively in the
warm bundle 202 and the middle bundle 204, and exits the middle
bundle through line 234. The refrigerant in line 234 may pass
through a control valve 241, which may be a J-T valve, according to
known liquefaction principles, and re-enters liquefaction heat
exchanger 200 via line 210, which is combined with the light
refrigerant in line 208. The combined refrigerant then provides
further cooling for the middle bundle 204 and the warm bundle 202
before leaving the liquefaction heat exchanger 200 through line
212.
[0040] FIG. 3 is a simplified elevation view of a liquefaction heat
exchanger 300 according to aspects of the present disclosure. The
liquefaction heat exchanger is commonly referred to as a main
cryogenic heat exchanger. Liquefaction heat exchanger 300 has three
sections of multi-pass heat exchange: a warm bundle 302, a middle
bundle 304, and a cold bundle 306. The lines identified by
reference numbers 308, 310, and 312 follow the heat exchanger cold
passes, which cool all the other passes--termed the warm passes--in
the heat exchanger. The liquefaction heat exchanger 300 may be
designed as a spiral-wound heat exchanger, in which case the warm
passes comprise bundles of small-bore tubing wound around a central
mandrel and the cold pass stream is sprayed over the bundles to
provide to cooling. Alternatively, the liquefaction heat exchanger
could be designed as a plate-fin heat exchanger, in which case the
warm passes and the cold passes are integrated into a core
exchanger separated by alternating plates. Other types of
liquefaction heat exchangers may be used, but for ease of
explaining herein the disclosed aspects, a spiral-wound heat
exchanger design will be described.
[0041] Referring to FIG. 3, the hydrocarbon gas to be liquefied,
which in disclosed aspects may be the dry gas stream 110 shown in
FIG. 1, enters the warm bundle 302 where it is pre-cooled to
condense heavy components, which might freeze in the colder
sections of the liquefaction heat exchanger. The warm bundle is
analogous to the precooling step 112 shown in FIG. 1. The
pre-cooled natural gas stream 314 leaves the liquefaction heat
exchanger so that condensed components such as heavy hydrocarbons
may be separated out. After separating out the condensed heavy
components, the natural gas stream returns through line 316 and
enters the middle bundle 304. The natural gas stream is condensed
in the middle bundle and leaves the middle bundle as a
high-pressure LNG stream through line 318. A gaseous or two-phase
stream of liquefied petroleum gases (LPGs) 320, which may be
generated by the fractionation step 114 of FIG. 1, is also passed
through the warm bundle 302 and the middle bundle 304 to produce a
cooled LPG stream 322. To combine the high pressure LNG stream in
line 318 with the cooled LPG stream 322, it is necessary to
let-down or reduce the pressure of the high pressure LNG stream.
According to aspects of the present disclosure, the high-pressure
LNG stream in line 318 is passed through a hydraulic turbine 323.
While the pressure let-down across a J-T valve is isenthalpic
(i.e., no energy removed), pressure let-down across the hydraulic
turbine 323 extracts energy in the form of work from the
high-pressure LNG stream 318. In so doing, the hydraulic turbine
323 contributes to the process of making the high-pressure LNG
stream 318 colder and thereby reduces the cooling duty of the
liquefaction heat exchanger 300. As the capacity of the
liquefaction heat exchanger 300 is typically limited by the power
of its associated refrigeration compression unit, the additional
refrigeration contribution from the hydraulic turbine 323 means
that a higher LNG production capacity can be achieved by the
liquefaction heat exchanger 300, compared to the liquefaction heat
exchanger 200 which uses only a J-T valve 224. However, in an
aspect, a J-T valve 324 may be disposed to bypass the hydraulic
turbine 323. J-T valve 324 provides a back-up function to the
hydraulic turbine. The J-T valve 324 may also be used for start-up
operation of the liquefaction heat exchanger 300. Additionally, the
J-T valve may be used in conjunction with the hydraulic turbine 323
if the flow of the LNG stream in line 318 exceeds the capacity of
the hydraulic turbine.
[0042] A control valve 325 may be disposed downstream of the
hydraulic turbine. The purpose of the pressure control provided by
the control valve 325 is to ensure the LNG stream 327 exiting the
hydraulic turbine is at a suitable pressure to mix with the cooled
LPG stream 322. The control valve 325 may also help to keep the LNG
stream in the liquid phase and prevent it from becoming a two-phase
stream. The combined LNG/LPG stream 326 is then sub-cooled as it
passes through the cold bundle 306, and leaves the liquefaction
heat exchanger as a medium-pressure LNG stream 328.
[0043] A light refrigerant stream 330 is cooled successively in the
warm bundle 302, the middle bundle 304, and the cold bundle 306,
and exits the cold bundle through line 331. The refrigerant in line
331 may pass through a control valve 333, which may be a J-T valve,
according to known liquefaction principles, and re-enters the cold
bundle via line 308, where it provides cooling for the cold bundle
306 through line 308. A heavy refrigerant in line 332 is cooled
successively in the warm bundle 302 and the middle bundle 304, and
exits the middle bundle through line 334. The refrigerant in line
334 may pass through a control valve 341, which may be a J-T valve,
according to known liquefaction principles, and re-enters
liquefaction heat exchanger 300 via line 310, which is combined
with the light refrigerant in line 308. The combined refrigerant
then provides further cooling for the middle bundle 304 and the
warm bundle 302 before leaving the liquefaction heat exchanger 300
through line 312.
[0044] As previously stated, pressure let-down across the hydraulic
turbine 323 extracts energy in the form of work from the
high-pressure LNG stream 318. This work may be used to power a
generator 340, for example. The generator may provide power to one
or more parts of the natural gas liquefaction process 100 or may
provide power to other processes, including an external electrical
grid. FIG. 4 is a more detailed schematic view of the hydraulic
turbine 323 operationally connected to the generator 340. A first
set of one or more sensors 402 may be positioned to measure the
pressure and/or temperature of the high-pressure LNG stream 318 as
it exits the middle bundle 304 (FIG. 3) or as it enters the
hydraulic turbine 323. A second set of one or more sensors 404 may
be positioned to measure the pressure and/or temperature of the LNG
stream 327 downstream of the hydraulic turbine 323. The performance
or functionality of various components depicted in FIG. 4 may be
adjusted based on the pressures and/or temperatures as sensed by
the first and/or second sets of one or more sensors 402, 404, such
as the operating speed of the generator 340, the operating speed of
the hydraulic turbine 323, the operating position of the control
valve 325, the operating position of the J-T valve 324, and/or the
rate at which the high-pressure LNG stream 318 is admitted into the
hydraulic turbine 323 (through turbine wicket gates 323a, for
example).
[0045] FIG. 5 is a schematic view of the hydraulic turbine 323 and
generator 340 according to another aspect of the disclosure. A
variable-speed constant-frequency (VSCF) drive 350 may be disposed
between and operationally connected to the generator 340 and a
power system 354, which may comprise an external power grid. The
VSCF drive 350 operates to selectively control the generator
operating speed based on an operator-defined speed set point. Such
action may convert the frequency of electrical output 352 from the
generator to match the power system frequency. The generator speed
set point in the VSCF drive may be adjusted based on the pressures
and/or temperatures as sensed by the first and/or second sets of
one or more sensors 402, 404.
[0046] It is possible for other components to be operationally
connected to the hydraulic turbine 323 in place of or in addition
to the generator 340. For example, FIG. 6 is a schematic view of
another aspect of the disclosure in which a mechanical brake 360 is
operationally connected to the hydraulic turbine 323. The
mechanical brake may be adjusted based on the pressures and/or
temperatures as sensed by the first and/or second sets of one or
more sensors 402, 404. Alternatively or additionally, as shown in
FIG. 7, a compressor such as a centrifugal compressor 370 may be
operationally connected to the hydraulic turbine via, for example,
a shaft 372. The centrifugal compressor 370 may be used to compress
one or more fluids in the natural gas liquefaction process 100 or
in other processes as desired.
[0047] Aspects of the disclosure may be modified in many ways while
keeping with the spirit of the disclosure. For example, the
generator 340 may also function as a motor to power up the
hydraulic turbine 323 during a start-up operation. Additionally,
more than one hydraulic turbine may be used in series and/or in
parallel with hydraulic turbine 323.
[0048] FIG. 8 is a method 800 of liquefying a natural gas stream to
produce liquefied natural gas (LNG) according to disclosed aspects.
At block 802 the natural gas stream is sequentially cooled in
first, second, and third cooling bundles of a liquefaction heat
exchanger. The second cooling bundle liquefies the natural gas
stream to produce an LNG stream. At block 804 the LNG stream is
cooled and its pressure is reduced between the second cooling
bundle and the third cooling bundle using a hydraulic turbine, to
thereby produce a reduced-pressure LNG stream. At block 806 work
energy is produced using the hydraulic turbine.
[0049] FIG. 9 is a method 900 of liquefying a natural gas stream to
produce liquefied natural gas (LNG). At block 902 the natural gas
stream is sequentially cooled in a liquefaction heat exchanger
having first, second, and third cooling bundles. The second cooling
bundle liquefies the natural gas stream to produce an LNG stream.
At block 904 the LNG stream is cooled and its pressure is reduced
between the second cooling bundle and the third cooling bundle
using a hydraulic turbine. At block 906 work energy is produced
using the hydraulic turbine. At block 908, using the work energy,
power is generated using a generator connected to the hydraulic
turbine. At block 910 the pressure of the LNG stream exiting the
hydraulic turbine is controlled using a control valve disposed
between the outlet of the hydraulic turbine and an inlet of the
third cooling bundle. At block 912 at least one of a speed of the
hydraulic turbine, an LNG inlet rate of the hydraulic turbine, a
position of the bypass valve, a position of the control valve, and
a speed of the generator, are adjusted based on at least one of a
sensed temperature of the LNG stream prior to entering the
hydraulic turbine, a sensed pressure of the LNG stream prior to
entering the hydraulic turbine, a sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and a sensed
pressure of the LNG stream as the LNG stream exits the hydraulic
turbine.
[0050] The aspects disclosed herein provide a method of expanding
and cooling a natural gas stream in a liquefaction heat exchanger.
This method is applicable in cryogenic heat exchangers used to
generate LNG, but may also be used in other cryogenic heat
exchangers. The method and system may be retrofitted into an
existing LNG producing facility, or may be designed into a new
facility. An advantage of the disclosed aspects is that work energy
can be extracted from the LNG within a liquefaction heat exchanger.
This work energy can be used advantageously in many ways, such as
by powering a generator, a mechanical brake, and/or a compressor.
Another advantage is that the temperature of the LNG stream is
lowered by passing through the hydraulic turbine. This reduces the
cooling duty of the liquefaction heat exchanger, and as a result
the capacity of the liquefaction heat exchanger can be
increased.
[0051] Aspects of the disclosure may include any combinations of
the methods and systems shown in the following numbered paragraphs.
This is not to be considered a complete listing of all possible
aspects, as any number of variations can be envisioned from the
description above. [0052] 1. A system for liquefying a natural gas
stream, comprising: [0053] a liquefaction heat exchanger having at
least three cooling bundles and arranged such that the natural gas
stream passes sequentially therethrough, including [0054] a first
cooling bundle configured to condense heavy hydrocarbon components
in the natural gas stream, [0055] a second cooling bundle
configured to liquefy the natural gas stream, the second cooling
bundle having an outlet for passing an LNG stream therethrough, and
[0056] a third cooling bundle having an inlet to receive the LNG,
the third cooling bundle configured to sub-cool the LNG stream; and
[0057] a hydraulic turbine having an inlet operationally connected
to the outlet of the second cooling bundle and an outlet
operationally connected to the inlet of the third cooling bundle,
the hydraulic turbine configured to cool the LNG stream and reduce
a pressure of the LNG stream to form a reduced-pressure LNG
stream.
[0058] 2. The system of paragraph 1, further comprising: [0059] a
first set of one or more sensors situated to sense at least one of
a pressure and a temperature of the LNG stream prior to entering
the hydraulic turbine; and [0060] a second set of one or more
sensors situated to sense at least one of a pressure and a
temperature of the LNG stream as the LNG stream exits the hydraulic
turbine. [0061] 3. The system of paragraph 2, wherein at least one
of a) a speed of the hydraulic turbine and b) an LNG inlet flow
rate to the hydraulic turbine is adjusted based on at least one of
the sensed temperature of the LNG stream prior to entering the
hydraulic turbine, the sensed pressure of the LNG stream prior to
entering the hydraulic turbine, the sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and the
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine. [0062] 4. The system of paragraph 2, further
comprising a bypass valve operationally connecting the outlet of
the second cooling bundle and the inlet of the third cooling bundle
such that, when open, at least a portion of the LNG stream bypasses
the hydraulic turbine. [0063] 5. The system of paragraph 4, wherein
the bypass valve is selectively controlled based on at least one of
the sensed temperature of the LNG stream prior to entering the
hydraulic turbine, the sensed pressure of the LNG stream prior to
entering the hydraulic turbine, the sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and the
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine. [0064] 6. The system of any of paragraphs 1-5,
further comprising a control valve disposed between the outlet of
the hydraulic turbine and the inlet of the third cooling bundle,
wherein the control valve is selectively controlled based at least
in part on one or more of a sensed temperature of the LNG stream
prior to entering the hydraulic turbine, a sensed pressure of the
LNG stream prior to entering the hydraulic turbine, a sensed
temperature of the LNG stream as the LNG stream exits the hydraulic
turbine, and a sensed pressure of the LNG stream as the LNG stream
exits the hydraulic turbine. [0065] 7. The system of any of
paragraphs 1-6, further comprising a generator connected to the
hydraulic turbine and configured to generate power based on the
work energy generated by the hydraulic turbine. [0066] 8. The
system of paragraph 7, further comprising: [0067] a first set of
one or more sensors situated to sense at least one of a pressure
and a temperature of the LNG stream prior to entering the hydraulic
turbine, and [0068] a second set of one or more sensors situated to
sense at least one of a pressure and a temperature of the LNG
stream as the LNG stream exits the hydraulic turbine; [0069]
wherein a speed of the generator is adjusted based on at least one
of the sensed temperature of the LNG stream prior to entering the
hydraulic turbine, the sensed pressure of the LNG stream prior to
entering the hydraulic turbine, the sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and the
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine. [0070] 9. The system of paragraph 7, further
comprising a variable-speed constant-frequency (VSCF) drive
situated between the generator and a power system, wherein the VSCF
drive is selectively controlled based at least in part on one or
more of the sensed temperature of the LNG stream prior to entering
the hydraulic turbine, the sensed pressure of the LNG stream prior
to entering the hydraulic turbine, the sensed temperature of the
LNG stream as the LNG stream exits the hydraulic turbine, the
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine and the power system frequency. [0071] 10. The
system of any of paragraphs 1-9, further comprising at least one of
a mechanical brake and a compressor operationally connected to the
hydraulic turbine. [0072] 11. The system of paragraph 10, wherein
the brake is selectively controlled based at least in part on one
or more of a sensed temperature of the LNG stream prior to entering
the hydraulic turbine, a sensed pressure of the LNG stream prior to
entering the hydraulic turbine, a sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and a sensed
pressure of the LNG stream as the LNG stream exits the hydraulic
turbine. [0073] 12. The system of any of paragraphs 1-11, further
comprising: [0074] a liquefied petroleum gas (LPG) stream
configured to pass through the first cooling bundle and the second
cooling bundle, the reduced-pressure LNG stream being at a pressure
so as to be combined with the LPG stream after the LPG stream has
passed through the second cooling bundle. [0075] 13. A method of
liquefying a natural gas stream to produce liquefied natural gas
(LNG), comprising: [0076] sequentially cooling the natural gas
stream in first, second, and third cooling bundles of a
liquefaction heat exchanger, wherein the second cooling bundle
liquefies the natural gas stream to produce an LNG stream; [0077]
cooling and reducing the pressure of the LNG stream between the
second cooling bundle and the third cooling bundle using a
hydraulic turbine, to thereby produce a reduced-pressure LNG
stream; and [0078] producing work energy using the hydraulic
turbine. [0079] 14. The method of paragraph 13, further comprising:
[0080] adjusting at least one of a) a speed of the hydraulic
turbine and b) an LNG inlet rate of the hydraulic turbine based on
at least one of a sensed temperature of the LNG stream prior to
entering the hydraulic turbine, a sensed pressure of the LNG stream
prior to entering the hydraulic turbine, a sensed temperature of
the LNG stream as the LNG stream exits the hydraulic turbine, and a
sensed pressure of the LNG stream as the LNG stream exits the
hydraulic turbine. [0081] 15. The method of paragraph 13 or
paragraph 14, further comprising: [0082] selectively directing at
least a portion of the LNG stream exiting the hydraulic turbine
through a bypass valve that operationally connects an outlet of the
second cooling bundle and an inlet of the third cooling bundle; and
[0083] selectively controlling the bypass valve based on at least
one of a sensed temperature of the LNG stream prior to entering the
hydraulic turbine, a sensed pressure of the LNG stream prior to
entering the hydraulic turbine, a sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and a sensed
pressure of the LNG stream as the LNG stream exits the hydraulic
turbine. [0084] 16. The method of any of paragraphs 13-15, further
comprising controlling a pressure of the LNG stream exiting the
hydraulic turbine by disposing a control valve between an outlet of
the hydraulic turbine and an inlet of the third cooling bundle,
wherein the control valve is selectively controlled based at least
in part on one or more of a sensed temperature of the LNG stream
prior to entering the hydraulic turbine, a sensed pressure of the
LNG stream prior to entering the hydraulic turbine, a sensed
temperature of the LNG stream as the LNG stream exits the hydraulic
turbine, and a sensed pressure of the LNG stream as the LNG stream
exits the hydraulic turbine. [0085] 17. The method of any of
paragraphs 13-16, further comprising: [0086] connecting a generator
to the hydraulic turbine; and generating power using the generator
based on the work energy generated by the hydraulic turbine. [0087]
18. The method of paragraph 17, further comprising: [0088]
adjusting a speed of the generator based on at least one of a
sensed temperature of the LNG stream prior to entering the
hydraulic turbine, a sensed pressure of the LNG stream prior to
entering the hydraulic turbine, a sensed temperature of the LNG
stream as the LNG stream exits the hydraulic turbine, and a sensed
pressure of the LNG stream as the LNG stream exits the hydraulic
turbine. [0089] 19. The method of paragraph 17, further comprising:
[0090] controlling an electrical output of the generator using a
variable-speed constant-frequency drive situated between the
hydraulic turbine and the generator. [0091] 20. The method of any
of paragraphs 13-19, further comprising: [0092] operationally
connecting at least one of a mechanical brake and a compressor to
the hydraulic turbine. [0093] 21. The method of any of paragraphs
13-19, further comprising: [0094] obtaining a liquefied petroleum
gas (LPG) stream from a fractionation process that occurs prior to
the natural gas stream being sequentially cooled in the
liquefaction heat exchanger; [0095] cooling the LPG stream in the
first cooling bundle and the second cooling bundle, the
reduced-pressure LNG stream being at a pressure so as to be
combined with the LPG stream after the LPG stream has passed
through the second cooling bundle. [0096] 22. The method of
paragraph 21, wherein the liquefaction heat exchanger is part of an
operating LNG process, and further comprising: [0097] retrofitting
the hydraulic turbine between the second cooling bundle and the
third cooling bundle. [0098] 23. A method of liquefying a natural
gas stream to produce liquefied natural gas (LNG), comprising:
[0099] sequentially cooling the natural gas stream in a
liquefaction heat exchanger having first, second, and third cooling
bundles, wherein the second cooling bundle liquefies the natural
gas stream to produce an LNG stream; [0100] cooling and reducing
the pressure of the LNG stream between the second cooling bundle
and the third cooling bundle using a hydraulic turbine; [0101]
producing work energy using the hydraulic turbine; [0102] using the
work energy, generating power using a generator connected to the
hydraulic turbine; [0103] controlling a pressure of the LNG stream
exiting the hydraulic turbine using a control valve disposed
between the outlet of the hydraulic turbine and an inlet of the
third cooling bundle; and [0104] adjusting at least one of [0105] a
speed of the hydraulic turbine, [0106] an LNG inlet rate of the
hydraulic turbine, [0107] a position of the control valve, and
[0108] a speed of the generator, based on at least one of a sensed
temperature of the LNG stream prior to entering the hydraulic
turbine, a sensed pressure of the LNG stream prior to entering the
hydraulic turbine, a sensed temperature of the LNG stream as the
LNG stream exits the hydraulic turbine, and a sensed pressure of
the LNG stream as the LNG stream exits the hydraulic turbine.
[0109] 24. The method of paragraph 23, further comprising: [0110]
when the hydraulic turbine is desired to be bypassed, selectively
directing at least a portion of the LNG stream exiting the middle
bundle through a bypass valve that operationally connects an outlet
of the second cooling bundle and an inlet of the third cooling
bundle; and [0111] adjusting a position of the bypass valve based
on at least one of the sensed temperature of the LNG stream prior
to entering the hydraulic turbine, the sensed pressure of the LNG
stream prior to entering the hydraulic turbine, the sensed
temperature of the LNG stream as the LNG stream exits the hydraulic
turbine, and the sensed pressure of the LNG stream as the LNG
stream exits the hydraulic turbine.
[0112] While the foregoing is directed to aspects of the present
disclosure, other and further aspects of the disclosure may be
devised without departing from the basic scope thereof, and the
scope thereof is determined by the claims that follow.
* * * * *