LIQUEFIED GAS

TECHNICAL FIELD

The present disclosure is directed, in general, to energy technologies, and more specifically, to a modified Claude process for producing liquefied gas.

BACKGROUND

Requirements often arise for liquefying gas. A gaseous substance such as natural gas may be easier or more economical to transport as liquefied natural gas ("LNG"). Liquefied air, nitrogen, oxygen, hydrogen, helium, and other liquefied gases are widely used in industry.

Producing liquefied gas requires at least the following steps: removing sensible heat and removing latent heat.

Numerous technologies have been developed to produce liquefied gas. Classical processes employ a cascade of single-component refrigerators, typically using propane, ethylene, and methane as the working fluids. More recently, mixed-refrigerant systems have been developed that use a blend of nitrogen, methane, ethylene, propane, and butane. One of the oldest processes for producing liquefied gas is based on the Claude process, which employs a combination of compressors and expanders to chill the gas. In the final step, the high-pressure chilled gas passes through a Joule-Thomson throttling valve where a portion of the gas liquefies. An exemplary system employing the Claude process is shown in FIGURE 1. Pretreated natural gas passes through a heat exchanger to reduce its temperature, and then the cooled natural gas passes through a Joule-Thomson valve to convert some of the cooled natural gas to liquefied natural gas. Other elements of the system of FIGURE 1 operate to cool a working fluid to a temperature below the temperature of the pretreated natural gas and to pass the cooled working fluid through the heat exchanger, which transfers heat from the natural gas to the working fluid to cool the natural gas. Although the system of FIGURE 1 is shown liquefying natural gas, it will be understood that the system could be used to liquefy other gases. Further, it is understood that the working fluid being compressed and expanded can be the same as the pretreated feed gas, or it can be different. SUMMARY

According to a first embodiment of the present disclosure, a system for liquefying gas includes a first combiner that forms a first blended stream from a combination of an input gas and a first portion of a first recycle stream. The system also includes a heat exchanger that transfers heat from the first blended stream to a second blended stream, producing a cooled first blended stream and a heated second blended stream. The system further includes a first expander that produces a mixture of gas and liquefied gas from the cooled first blended stream, and an outlet to produce the liquefied gas. The system still further includes a first compressor that produces a second recycle stream from the gas from the mixture of gas and liquefied gas. The system also includes a second combiner that forms the second blended stream from the second recycle stream and a third recycle stream and provides the second blended stream to the heat exchanger. The system further includes a second compressor that receives the heated second blended stream from the heat exchanger and produces the first recycle stream and provides the first portion of the first recycle stream to the first combiner. The system still further includes a second expander that receives a second portion of the first recycle stream and produces the third recycle stream and provides the third recycle stream to the second combiner.

According to a second embodiment of the present disclosure, a method of liquefying gas includes combining an input gas and a first portion of a first recycle stream to form a first blended stream. The method also includes producing a cooled first blended stream and a heated second blended stream by passing the first blended stream and a second blended stream through a heat exchanger adapted to transfer heat from the first blended stream to the second blended stream. The method further includes producing a mixture of gas and liquefied gas from the cooled first blended stream using a first expander, and producing the liquefied gas at an outlet. The method still further includes producing a second recycle stream from the gas from the mixture of gas and liquefied gas using a first compressor, and combining the second recycle stream and a third recycle stream to form the second blended stream. The method also includes producing the first portion and a second portion of the first recycle stream from the heated second blended stream using a second compressor, and producing the third recycle stream from the second portion of the first recycle stream using a second expander.

According to a third embodiment of the present disclosure, a gas liquefying system includes a heat exchanger and a gerotor expander. The heat exchanger receives an input gas and produces a cooled gas. The gerotor expander receives the cooled gas and to produce a mixture of gas and liquefied gas. Before undertaking the DETAILED DESCRIPTION below, it may be advantageous to set forth definitions of certain words and phrases used throughout this patent document: the terms "include" and "comprise," as well as derivatives thereof, mean inclusion without limitation; the term "or," is inclusive, meaning and/or; the phrases "associated with" and "associated therewith," as well as derivatives thereof, may mean to include, be included within, interconnect with, contain, be contained within, connect to or with, couple to or with, be communicable with, cooperate with, interleave, juxtapose, be proximate to, be bound to or with, have, have a property of, or the like.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and its advantages, reference is now made to the following description taken in conjunction with the accompanying drawings, in which like reference numerals represent like parts:

FIGURE 1 shows an exemplary system employing the Claude process to liquefy natural gas;

FIGURE 2 shows a first system for liquefying gas according to this disclosure;

FIGURE 3 shows a second system for liquefying gas according to this disclosure;

FIGURE 4 shows appropriate gas pressure as a function of gas temperature in a system for liquefying methane according to this disclosure;

FIGURE 5 shows energy consumption for a system for liquefying methane according to this disclosure;

FIGURE 6 shows a calculation of a theoretical minimum energy consumption for producing LNG assuming the gas is pure methane; and

FIGURE 7 shows typical energy consumption for various processes that produce LNG.

DETAILED DESCRIPTION

It should be understood at the outset that, although example embodiments are illustrated below, the present invention may be implemented using any number of techniques, whether currently known or not. The present invention should in no way be limited to the example implementations, drawings, and techniques illustrated below. Additionally, the drawings are not necessarily drawn to scale.

FIGURE 2 shows a system 200 for liquefying natural gas according to this disclosure. The system 200 is similar to the Claude process, however an expander 202 replaces the Joule- Thomson valve. In both FIGURE 1 and FIGURE 2, the liquefaction process is incomplete so the LNG discharge contains gas that must be recycled. The expander 202 allows a greater portion of the gas to liquefy and thereby improves efficiency of the system 200 over the system shown in FIGURE 1. However, the expander 202 must be able to tolerate the presence of liquid.

Dynamic expanders (e.g., centrifugal, axial) must operate at high tip speeds, which makes the equipment susceptible to erosion by liquids. In contrast, positive displacement expanders (e.g., reciprocating, screw, sliding vane, and gerotors) operate at lower speeds and can more readily tolerate liquids. However, reciprocating expanders have valves that can interfere with the discharge of liquids, which risks damaging the machine if the reciprocating piston attempts to compress retained liquid. Both screw and sliding-vane expanders require a lubricant fluid for lubricating and sealing purposes, which becomes mixed with the liquefied gas produced by the expander and must be removed in a subsequent, additional step. Because the expander is very cold, it is difficult to find a suitable lubricant that remains liquid at cryogenic temperatures.

In contrast, gerotors do not have these operational shortcomings. Generally, the competing expanders are approximately 50 to 80% efficient, depending on scale. In contrast, gerotor expanders are 80 to 90% efficient, which is required to make gas liquefying systems according to this disclosure economically attractive.

StarRotor Corporation of College Station, TX, has developed gerotor expanders that may be used in gas liquefying systems according to this disclosure. Certain embodiments of this disclosure may avail from other StarRotor technologies disclosed, for example, in United States

Patent No. 7,186,101, United States Patent No. 7,695,260, and United States Printed Publication

No. 2011/0200476 - the contents of all three disclosures are incorporated herein by reference.

By optimizing the process configuration, the modified Claude process is extremely efficient and approaches the theoretical minimum energy requirement to produce LNG. By inference, the process should be similarly efficient for other gases. Further advantages of the process are its simplicity and the fact that it requires no additional working fluids other than the gas being liquefied.

FIGURE 3 shows a system 300 for liquefying gas according to this disclosure. The system 300 illustrates the process of liquefying natural gas, however the system 300 may be engineered to liquefy any gas. In FIGURE 3, input stream of natural gas 302 is supplied at pipeline pressure (approx. 5.3 MPa, or 780 psia) and a temperature of approx. 35°C (or 95°F). If the gas is not available at high pressures, an additional compression step is required to feed the gas at high pressure.

The pipeline gas 302 is blended at combiner 304 with a first recycle stream 306 from a compressor section 308. First blended stream 309 flows through a sensible heat exchanger 310 where it is pre-cooled to temperature T ₂ . Then, the first blended stream 309 flows through expander El where the pressure is lowered to approx. 0.1 MPa (1 atmosphere). Work is extracted in the expander El, which rotates a shaft 312.

Expander El cools the first blended stream 309 and liquefies a portion of it. The resulting LNG 315 is knocked out of the expander discharge in a container 316 and is produced at an outlet 314. The natural gas that remains as vapor 318 is recycled and is fed to compressor CI where it is pressurized to pressure P and temperature to form second recycle stream 322. As will be discussed in more detail below, compressor CI is powered by shaft 312. The second recycle stream 322 is blended at combiner 324 with a third recycle stream 326 from the compressor section 308 to form a second blended stream 328, which is passed through the sensible heat exchanger 310. The temperature of the second blended stream 328 is colder than the first blended stream 309, so the second blended stream 328 extracts heat from the first blended stream 309 and becomes warmer. The second blended stream 328 emerges from the sensible heat exchanger 310 at approx. 25°C and is sent to the compressor section 308.

The heat exchanger of FIGURE 1 and FIGURE 2 includes the compressed working fluid from the booster compressor along part of the heat exchanger, but not the entire length. As a result, the heat duty varies in different sections of the heat exchanger, which makes it impossible to maintain a substantially uniform temperature difference along the length. In some portions of the heat exchanger, the temperature difference will be large, which results in thermodynamic irreversibilities that reduce energy efficiency.

In contrast, the heat exchanger 310 of the system 300 includes only the first blended stream 309 and the second blended stream 328, both of which flow along the entire length. Further, the mass flow rate of the two streams is substantially the same. This allows the heat exchanger 310 to maintain a substantially constant temperature differential along its length between the first blended stream 309 and the second blended stream 328. This uniform and small temperature difference reduces thermodynamic irreversibilities, which improves energy efficiency.

In the compressor section 308, the second blended stream 328 is compressed in a series of compressors with inter-stage cooling. As will be discussed in more detail below, the compressors of the compressor section 308 are powered by shaft 312. In Figure 3, five compression stages are shown; however, more or fewer stages can be used. More stages will improve efficiency because the compression approaches isothermal conditions. Fewer stages will reduce capital costs.

Compressed gas 330 exiting the compressor section 308 is split into two portions. A first portion, the first recycle stream 306, is blended with the incoming pipeline gas 302, as described above. In some configurations, the pipeline gas 302 has substantially the same temperature and pressure as the compressed gas 330 (and the first recycle stream 306). However, in other configurations, the temperature and/or pressure may be different. The second portion of the compressed gas 330, stream 332, is coupled to expander E2. Work is extracted in the expander E2, which rotates the shaft 312. Discharge from the expander E2, the third recycle stream 326, is blended at the combiner 324 with the second recycle stream 322 from the compressor CI . As mentioned above, a single drive shaft 312 may be common to all expanders and compressors of the system 300. Work extracted from the expanders El and E2 contributes to rotating the shaft 312. In turn, the shaft 312 operates to rotate the compressors CI through C6. A motor 334 is also coupled to the shaft 312 to compensate for inefficiencies in components of the system 300 and to provide the work done by the system 300 in liquefying the pipeline gas 302.

The following equations further describe the design of the system 300,

where Q = is the heat duty of heat exchanger 310, m = mass of the compressed gas in the recycle stream 306, n = mass of the gas in the second blended stream 328, H _h = enthalpy of the first blended stream 309 entering the heat exchanger 310, ¾ ₀ = enthalpy of the first blended stream 309 exiting the heat exchanger 310, Hu = enthalpy of the second blended stream 328 entering the heat exchanger 310, and H _{/ 0} = enthalpy of the second blended stream 328 exiting the heat exchanger 310. Further,

Φ— Vapor fraction ~

1 + ίίί

ff }—— --—

1 - φ

To increase efficiency, the pressure of the compressed gas 330 exiting the compressor section 308 is selected so that its entropy is substantially the same as the entropy of the vapors 318 in equilibrium with the LNG 315. By following this rule and assuming isentropic compression/expansion, the gas temperatures discharged from the compressor CI and the expander E2 will be identical, which eliminates inefficiencies in the combiner 324 associated with mixing two gases of differing temperatures. FIGURE 4 shows the appropriate theoretical gas pressure discharged from the compressor section 308 as a function of gas temperature discharged from the compressor section 308.

It should be emphasized that the pressures and temperatures used in the above illustration are examples only. The LNG 315 may be stored at pressures other than 0.1 MPa and the pipeline gas 302 may be supplied at pressures other than 5.3 MPa and temperatures other than 35°C. To achieve optimal performance, it may be necessary to pre-compress or pre-expand the pipeline gas 302 to match the pressure exiting the compressor section 308 in the system 300.

FIGURE 5 shows the energy consumption for the system 300 as a function of the heat exchanger inlet temperature and the efficiency of the all compressors and expanders in the system, which are assumed to be the same for simplicity. Energy consumption is minimal at the "sweet spot" {T _\ = -90 to -95°C; P = 0.7 MPa.) At the sweet spot, the energy consumption is 0.18 to 0.30 kWh/kg at compressor/expander efficiencies of 95 to 80%, respectively. It should be noted that the energy consumption reported in FIGURE 5 is idealized and does not include the impact of compressor and expander inefficiencies on mass flows.

The theoretical minimum energy consumption (0.147 kWh/kg) for any system producing LNG is calculated in FIGURE 6. This value is similar to a literature value (0.133 kWh/kg), which used a slightly different reference condition. See C.W. Remeljej, A.F.A. Hoadley, An exergy analysis of small-scale liquefied natural gas (LNG) liquefaction processes, Energy, 31 , 2005-2019 (2006) ("Remeljej").

Assuming the compressors and expanders have efficiencies of about 90%, the energy consumption is 0.22 kWh/kg LNG. Assuming electricity sells for $0.036/kWh, this is equivalent to $0.0203/gal diesel equivalent - roughly two pennies per gallon of diesel equivalent. A world-scale LNG plant produces about 5 million tonne per year. See Remeljej. Reducing energy consumption from 0.35 to 0.22 kWh/kg saves $23.4 million per year at $0.036/kWh.

The above discussion emphasizes the energy efficiency at large scale (90%> compressor efficiency). Even at small scale, gerotor compressors are very efficient (~85% efficiency); thus the system 300 will scale down for regional LNG plants that can service trucking routes without transporting large quantities of LNG on the highways. The above discussion is repeated for a regional plant.

A regional LNG plant will have compressors and expanders with efficiencies of about

85%). At this efficiency level, the energy consumption is 0.26 kWh/kg LNG. This energy consumption can be expressed as a percentage of the energy content of the natural gas

„ „ „- , kW-hwork 3600 s kJ work kg MJ heat . kJ work

Energy Fraction = 0.26 x x x x = 0.0169

kg LNG h kW-s 55.5 MJ heat 1000 kJ heat kJ eat

If an engine is 40% efficient, 4.2% of the natural gas must be burned to liquefy the remaining 95.8%.

When expressed on a volume basis in traditional units, the energy consumption is 0.417 kWh/gal LNG.

. ^kwh 423.97 kg m ³ 3.78 L _{n λ Λ} kWh

Work = 0.26 x ^ x x = 0.417

kg LNG m ³ 1000 L gal gal LNG

Retail electricity sells for about $0.12/kWh [5]; thus, it takes $0.05 to liquefy a gallon of natural gas - roughly one nickel per gallon of LNG. Expressed per gallon of diesel equivalent, the energy cost of liquefying LNG is

. ^kwh kg LNG 44.8 MJ 0.840kg 3.78 L kWh

Work = 0.26 x— - x x - x = 0.666

kg LNG 55.5 MJ kg diesel L gal gal LNG

Again, assuming electricity sells for $0.12/kWh, this is equivalent to $0.08/gal diesel equivalent - roughly a dime per gallon of diesel equivalent.

As shown in FIGURE 7, small simple LNG systems require 2 to 3 times more energy than the system 300. On a diesel equivalent basis, the energy cost for their system is about $0.16 to $0.24/gallon of diesel equivalent.

Modifications, additions, or omissions may be made to the systems, apparatuses, and methods described herein without departing from the scope of the invention. The components of the systems and apparatuses may be integrated or separated. Moreover, the operations of the systems and apparatuses may be performed by more, fewer, or other components. The methods may include more, fewer, or other steps. Additionally, steps may be performed in any suitable order. As used in this document, "each" refers to each member of a set or each member of a subset of a set.

To aid the Patent Office, and any readers of any patent issued on this application in interpreting the claims appended hereto, applicants wish to note that they do not intend any of the appended claims or claim elements to invoke paragraph 6 of 35 U.S.C. Section 112 as it exists on the date of filing hereof unless the words "means for" or "step for" are explicitly used in the particular claim.