Patent Grant
9557101
This is a U.S. national stage of application No. PCT/FR2012/051428, filed on Jun. 22, 2012. Priority is claimed on France Application No. FR1155595, filed Jun. 24, 2011, the content of which is incorporated herein by reference.
The present invention relates to a process for liquefying natural gas in order to produce liquefied natural gas (LNG). Still more particularly, the present invention relates to liquefying natural gas comprising a majority of methane, preferably at least 85% methane, with the other main constituents being selected from nitrogen and C-2 to C-4 alkanes, i.e. ethane, propane, and butane.
The present invention also relates to a liquefaction installation on board a ship or a floating support at sea, either on the open sea or in a protected zone such as a port, or indeed an installation on land for small or medium natural gas liquefaction units.
With an installation on board a ship, the present invention relates more particularly to a process for reliquefying gas on board an LNG transport ship, known as a “methane tanker”, said gas for reliquefying being the result of the LNG contained in the tank of said ship heating and evaporating in part, said evaporated gas, generally a majority of methane, being referred to as “boil-off”.
The methane-based natural gas is either a by-product of oil fields, being produced in small or medium quantities, in general in association with crude oil, or else it is a major product from a gas field, where it is to be found in combination with other gases, mainly C-2 to C-4 alkanes, CO2, and nitrogen.
When the natural gas is associated in small quantities with crude oil, it is generally treated and separated and then used on site as fuel for turbines or piston engines in order to produce electricity and heat for use in the separation or production processes.
When the quantities of natural gas are large, or indeed substantial, they need to be transported so that they can be used in regions far away, in general on other continents, and in order to do this the preferred method is to transport the gas while it is in the cryogenic liquid state (−165° C.) and substantially at ambient atmospheric pressure. Specialized transport ships known as “methane tankers” possess tanks of very large dimensions with extreme insulation in order to limit evaporation while traveling.
Gas is generally liquefied for transport purposes in the proximity of the production site, generally on land, and that requires substantial installations in order to achieve capacities of several millions of (metric) tonnes per year, with the largest existing units combining three or four liquefaction units, each having a unit capacity of 3 megatonnes (Mt) to 4 Mt per year.
The liquefaction process requires substantial quantities of mechanical energy, with the mechanical energy generally being produced on site by taking a portion of the gas in order to produce the energy needed by the liquefaction process. A portion of the gas is then used as fuel in gas turbines, steam turbines, or piston engines.
Numerous thermodynamic cycles have been developed for the purpose of optimizing overall energy efficiency. There are two main types of cycle. A first type is based on compressing and expanding a refrigerant fluid with a change of phase, while a second type is based on compressing and expanding a refrigerant gas without a change of phase. The terms “refrigerant fluid” and “refrigerant gas” are used to designate a gas or gas mixture circulating in a closed circuit and being subjected to stages of compression, possibly of liquefaction, then of heat exchange with the external medium, and subsequently stages of expansion, possibly of evaporation, and finally of heat exchange with the natural gas for liquefying, which gas comprises methane, and cools little by little to reach its liquefaction temperature at atmospheric pressure, i.e. about −165° C. for LNG.
Said first cycle type with a change of phase is generally used in installations on land and it requires a large amount of equipment and occupies a large footprint. In addition, the refrigerant fluids, generally in the form of mixtures, are constituted by butane, propane, ethane, and methane, which gases are dangerous since in the event of a leak they run the risk of leading to substantial fires or explosions. In contrast, in spite of the complexity of the equipment required, they remain more efficient and they require about 0.3 kilowatt hours (kWh) of energy per kilogram (kg) of LNG that is produced.
Numerous variants of that first type of process with a change of phase in the refrigerant fluid have been developed, and suppliers of technology or of equipment have their own formulations of mixtures associated with their specific equipment, both for so-called “cascade” processes and for so-called “mixed cycle” processes. The complexity of those installations comes from the fact that in those stages where the refrigerant fluid is in the liquid state, and more particularly in separators and in connection pipes, it is appropriate to install gravity collectors in order to bring the liquid phase together and direct it to the cores of heat exchangers where it vaporizes on coming into contact with the methane for cooling and liquefying in order to obtain LNG. Those devices are very bulky, but that does not lead to problems for installations on land, since it is generally simple to obtain an area of land that is large enough to house all of those bulky pieces of equipment side by side. Thus, for installations on land, all of the compressor, heat exchanger, and collector pieces of equipment are generally installed side by side on substantial areas, lying in the range 25,000 square meters (m2) to 50,000 m2, or even more.
The second type of liquefaction process, without any change of phase in the refrigerant gas, is an inverse Brayton cycle or a Claude cycle using a gas such as nitrogen. The efficiency of the second type of process is lower, since it generally requires about 0.5 kWh of energy per kg of LNG produced, i.e.; about 20.84 kilowatt-days per tonne (kW×d/t), but in contrast it presents a substantial advantage in terms of safety since the cycle refrigerant gas, nitrogen, is inert and thus incombustible, which is very advantageous when the installations are concentrated in a small amount of space, e.g. on the deck of a floating support located in the open sea, where said equipment is often installed on a plurality of levels one above another on an area that is reduced to the strict minimum. Thus, in the event of the refrigerant gas leaking, there is no danger of explosion and it then suffices to reinject into the circuit the fraction of the refrigerant gas that has been lost.
Furthermore, that process for liquefying natural gas without a change of phase is very advantageous on board floating supports since the equipment is of much simpler design, because there is no liquid phase in the refrigerant gas. In such installations, all of the equipment is moving practically continuously as a result of the movements of the floating support (roll, pitching, yaw, lurch, surge, heave). Managing a process with a phase change involving a liquid phase of the refrigerant fluid would then be extremely difficult, even for small movements of the floating support, and indeed practically impossible for extreme movements, whereas stationary installations on land do not face the problem of movements.
In spite of the lower energy efficiency of the liquefaction process without a change of phase of the refrigerant gas, this process remains very advantageous since the equipment used, mainly compressors, expanders, turbines, and heat exchangers is much simpler than the equipment required for a liquefaction process involving cycles with a change of phase in a refrigerant fluid, both in terms of the technology used for said equipment and in terms of maintaining the equipment in an environment that is confined, i.e. on board a floating support that is anchored at sea. Furthermore, the running of such installations in operation remains simpler, since this type of cycle is relatively insensitive to variations in the composition of the gas for liquefying, i.e. a natural gas that is constituted by a mixture in which methane predominates. In the cycle with a change of phase in the refrigerant fluid, in order to ensure that efficiency remains good, the refrigerant fluid needs to be matched to the nature and the composition of the gas that is to be liquefied, and the composition of the refrigerant fluid might possibly need to be modified over time as a function of the composition of the natural gas mixture for liquefying as produced by the oil field.
In principle, implementing a cycle of the liquefaction process without a change of phase in the refrigerant gas, such as nitrogen, comprises the four following main elements:
Throughout the duration of the cycle, the refrigerant gas remains in the gaseous state and it circulates in continuous manner, as explained above: it releases its “frigories” little by little, i.e. absorbs calories little by little from the gas that is to be liquefied, i.e. a mixture that is constituted for the most part by methane together with traces of other gases.
The gas for liquefying flows as a countercurrent relative to the refrigerant gas, i.e. said natural gas comprising methane enters the heat exchanger substantially at ambient temperature close to the refrigerant gas outlet where the refrigerant gas is substantially at ambient temperature. Thereafter, the natural gas comprising methane advances into the heat exchanger towards colder zones and transfers its heat to the refrigerant fluid: the natural gas comprising methane cools while the refrigerant gas heats up. As the natural gas comprising methane advances into the heat exchanger, its temperature drops, and at the end of its travel it liquefies and its temperature continues to drop until it reaches a temperature T3=−165° C. for a gas containing 85% methane.
Throughout its passage through the heat exchanger(s), the natural gas is liquefied at a pressure P0 lying in the range 5 bars to 50 bars, in general in the range 10 bars to 20 bars, in four main stages:
Stage 2 consumes the most energy, since it is necessary to supply the gas with all of the energy that corresponds to its latent heat of vaporization. Stage 1 consumes a little less energy, and stage 3 consumes least energy, but it takes place at the lowest temperatures, i.e. at temperatures around −165° C.
The values given above for T1, T2, and T3 are appropriate for a natural gas comprising 85% methane and 15% of said other components comprising nitrogen and C-2 to C-4 alkanes, and those temperatures may be significantly different for a gas having a different composition.
US 2011/0113825 and WO 2005/071333 describe a process for liquefying natural gas in which said natural gas for liquefying is liquefied by causing the natural gas to flow through three cryogenic heat exchangers, while causing three streams of refrigerant gas that remains in the compressed gaseous state without a change of phase to circulate in three closed circuits. Said natural gas for liquefying is liquefied by performing the following concurrent steps:
a) causing said natural gas for liquefying to flow at a pressure P0 that is higher than or equal to atmospheric pressure through the three cryogenic heat exchangers connected in series, namely:
b) causing two streams of the refrigerant gas in the gaseous state at different pressures P1 and P2, referred to respectively as first and third streams, to circulate through two of said heat exchangers in indirect contact with and as a countercurrent relative to the natural gas steam, comprising:
c) said second refrigerant gas stream compressed at the pressure P3 being obtained by compression in three or four compressors and by cooling said first and second refrigerant gas streams leaving said first heat exchanger respectively at P1 and at P2.
In US 2011/0113825, first and second compressors 113 and 114 are connected in series to compress the refrigerant gas of the first and second streams to P′3, and two other compressors 115a and 115b connected in parallel compress it from P′3 to P3.
In WO 2005/071333, two series-connected compressors 2 and 3 compress said first stream 16d to P′3, and then a third compressor 4 connected in series with the first two compressors compresses said first and third streams to P3.
In the report on the “24th International Conference and Exhibition for the LNG” of May 25, 2009, by Olve Skjeggedal et al. published in the GASTECH 2009 journal, a process of the above-described type having three closed-circuit refrigerant gas streams is described in which said first and second streams are compressed to P′3 by two compressors connected in series, and two other compressors connected in series compress said first and third streams to P3 in order to deliver said second stream.
The process described above is advantageous compared with that of
Nevertheless, in the embodiment of US 2011/0113825, all of the external power delivered to said series-connected first and second compressors 113 and 114 relates to the refrigerant gas streams circulating at low and medium pressures P1 and P2, with the energy recovered from the turbines 111 and 112 being reinjected to the two parallel-connected compressors 115a and 115b for compressing the refrigerant gas to high pressure P′3/P3, with no other additional external power being delivered to said parallel-connected compressors 115a and 115b. The two parallel-connected compressors 115a and 115b are powered solely by respective ones of the two energy recovery turbines 111 and 112.
The pressure levels P1 and P2 of the gas leaving the turbines 112 and 111 are different and thus the flow rates of the streams passing through the expanders 111 and 112 are different, and in practice they lie in particular in the range 10% to 20% of the total flow rate for the flow rate of the stream coming from the expander 112, as compared with 80% to 90% for the flow rate of the stream coming from the expander 111. As a result, the compressor 115b recovers only 10% to 20% of the total recovered power compared with the 80% to 90% of the power that is recovered in the compressor 115a. This mismatch in the powers delivered to the two parallel-connected compressors 115a and 115b leads to a major difficulty in stabilizing the operation of the circuit. Running two compressors in parallel can lead to surge phenomena, i.e. one of the compressors prevails over the others by disturbing their inlet and outlet pressures: there is then a risk of one or more of the smaller-capacity compressors operating in “turbine mode”. It is essential to avoid this mode of operation since some or all of the fluid then loops between the compressors, one operating in compressor mode and the other(s) in “turbine mode”: the compression process is then greatly disturbed or even interrupted, and the overall efficiency of the installation then collapses.
The operation of the circuit can be stabilized in conventional manner by means of regulation valves upstream and/or downstream from said parallel-connected compressors 115a and 115b, and/or upstream and/or downstream from said turbines 111 and 112 in order to control the flow rates and the operation of the compressors. Nevertheless, those regulation valves lead to head losses, and thus to losses of energy, thereby greatly affecting the expected overall efficiency and/or the production capacity of the installation.
In WO 2005/071333 and in the report in the above-mentioned GASTECH 2009 journal, all of the compressors are mechanically coupled to a common power source, with all of the power being delivered in undifferentiated manner among the various compressors.
An object of the present invention is to provide a natural gas liquefaction process of the type with no phase change in the refrigerant gas that is suitable for being installed on board a ship or a floating support and that presents improved energy efficiency, i.e. that minimizes the total energy consumed by the process in terms of kWh in order to obtain 1 tonne of LNG, and/or that presents increased transfers of heat in the heat exchangers, and/or that makes it possible to implement a liquefaction installation that is more compact and more efficient.
To do this, the present invention provides a process for liquefying natural gas comprising a majority of methane, preferably at least 85% methane, the other components essentially comprising nitrogen and C-2 to C-4 alkanes, wherein said natural gas for liquefying is liquefied by causing said natural gas to flow at a pressure P0 higher than or equal to atmospheric pressure (Patm), P0 preferably being higher than atmospheric pressure, through that least one cryogenic heat exchanger (EC1, EC2, EC3) by flowing in a closed circuit as a countercurrent in indirect contact with at least one stream of refrigerant gas that remains in the gaseous state and that is compressed to a pressure P1 entering said cryogenic heat exchanger at a temperature T3′ lower than T3, T3 being the temperature on leaving said cryogenic heat exchanger, and T3 being lower than or equal to the liquefaction temperature of said liquefied natural gas at atmospheric pressure, wherein said natural gas for liquefying is liquefied by performing the following concurrent steps:
a) causing said natural gas for liquefying to flow at a pressure P0 higher than or equal to atmospheric pressure, P0 preferably being higher than atmospheric pressure, through at least three cryogenic heat exchangers connected in series and comprising:
b) causing at least two streams of refrigerant gas in the gaseous state and referred to respectively as the first and third streams to circulate in closed-circuits at different pressures P1 and P2 passing through at least two of said heat exchangers in indirect contact with and as a countercurrent relative to the natural gas stream and comprising:
c) said second stream of refrigerant gas compressed to the pressure P3 being obtained by using at least two compressors and by cooling, to compress said first and third streams of refrigerant gas leaving said first heat exchanger at P1 and P2 respectively, a first compressor compressing from P1 to P2 all of said first stream of refrigerant gas leaving said first heat exchanger, and at least one second compressor compressing firstly said third stream of refrigerant gas leaving said first heat exchanger at P2 and secondly said first stream of refrigerant gas compressed to P2 and leaving said first compressor, from P2 to at least P′3, where P′3 is a pressure lower than or equal to P3 and higher than P2, thereby obtaining said second stream of refrigerant gas at P3 and T0 after cooling, said second compressor being connected in series with said first compressor;
the process being characterized in that:
In the present description, the terms “compressor coupled to an expander/turbine or motor” or indeed “compressor driven by a motor” (or vice versa “expander/turbine or motor coupled to the compressor”) are used to mean that the outlet shaft from the turbine or the motor, as the case may be, drives the inlet shaft of the compressor, i.e. transfers mechanical energy to the shaft of the compressor. This is thus mechanical coupling of the compressor to the expander/turbine or respectively of the compressor to the motor.
More particularly, said motor may either be a fuel-burning engine, or else it is preferably an electric motor, or any other installation capable of delivering mechanical energy to the refrigerant gas; the compressors are of the rotary turbine type, also known as centrifugal compressors.
Preferably, after step a), the liquefied natural gas leaving said third heat exchanger at T3 is depressurized down from the pressure P0 to atmospheric pressure, where appropriate.
The process of the invention is advantageous compared with the process described in US 2011/0113825 in that all of the compressors are connected in series without requiring flow rates to be controlled by flow rate regulator valves in order to stabilize the operation of the installation. In the process of the invention, there is no separation of streams in the compression line. As a result, energy and/or stream flow rate is/are regulated in the various compressors essentially by regulating the amount of power delivered by said first and second motors and said gas turbine. It is not essential to use regulator valves in association with said compressors and said turbine because said first and second expanders are coupled to said first and second compressors that are connected in series and are therefore not coupled to compressors that are connected in parallel as in US 2011/0113825.
Furthermore, in the present invention, the major fraction of the energy delivered to said compressors is injected via the second and/or third compressors compressing the refrigerant gas stream to high pressure P′3/P3, and the energy recovered from the first and second expanders is reinjected via the first and second compressors serving to compress the refrigerant gas flowing at low and medium pressures P1 and P2. The fraction of the fluid passing through the compressor C1 is a small fraction of the total flow rate (e.g. 10% to 15%) and the energy needed is of the same order of magnitude as the energy recovered by the turbine E1. It is therefore advantageous to couple them together. Furthermore, controlled addition of power at C1 serves to improve the energy efficiency of the system by controlling P1 and P2 independently of each other.
Furthermore, the major portion of the power delivered to the compressors is injected into the compressors that supply the greatest pressure (P′3, P3), thereby making it possible to increase the production capacity of the process, while improving its energy efficiency.
In addition, using said first and second compressors in series and coupled to said first and second expanders in accordance with the present invention, thus makes it possible to improve the compactness of the installation, which is particularly advantageous for performing the process on board a floating support where space is limited.
The process of the invention as described with reference to
Furthermore, the process of the invention is advantageous compared with WO 2005/071333 and with the process described in the above-mentioned journal GASTECH 2009, in that it makes it possible to vary said pressure P2 in controlled manner so that the energy (Ef) consumed for performing the process is minimized. In the present invention, it is possible to modulate and control specifically the value of the pressure P2 by delivering different amounts of power to said first compressor by means of said first motor, thus making it possible to modulate and control the power delivered to the various compressors in different manners, and thus cause the value of P2 to vary.
Thus, according to an original characteristic of the present invention, said pressure P2 is caused to vary in controlled manner by delivering power in controlled manner to said first compressor from said first motor, in such a manner that the energy consumed for performing the process (Ef) is minimized, preferably when the composition of the liquid gas for liquefying varies.
This process is particularly advantageous since by modulating and controlling specifically the value of the pressure P2 of said third stream, it thus makes it possible to modify and optimize the operating point of the process, i.e. to minimize energy consumption and thus increase efficiency, in particular when the composition of the natural gas for liquefying varies, as happens in operation.
More particularly, said first motor delivers at least 3%, and preferably 3% to 30%, of the total power delivered to all of said compressors in use, said gas turbine supplying 97% to 70% of the total delivered power.
Still more particularly, it is observed that when the power injected via said first motor is increased, the pressure P1 remains substantially constant, the pressure P2 increases, and efficiency increases, i.e. the energy consumption expressed in kW×d/t decreases down to a minimum, after which any further increase in the power delivered by said motor, in particular to more than 30% of the total power, causes said energy consumption to increase once more.
A conventional liquefaction unit is dimensioned relative to the powers delivered by available gas turbines, with high power turbines currently delivering 25 megawatts (MW) or even 30 MW when they are for installation on board a floating support. Stationary gas turbines installed on land may reach maximum powers in the range 90 MW to 100 MW.
In general, it is desired to increase the power of the installation and it is then possible to install two identical gas turbines in parallel in order to obtain twice the power, but there are then two rotary machine lines which increases overall bulk, increases the quantity of pipework, and naturally increases costs.
By installing a single gas turbine GT that delivers nMW and by adding power of lower than nMW via a said second motor M2, the operation of the process is identical in terms of efficiency to that obtained when using two nMW gas turbines in parallel.
Thus, adding power via the second motor M2, preferably using an electric motor, gives greater flexibility in operation and thus enables power to be increased. However overall efficiency remains unchanged.
In contrast, if the same power is delivered via a first motor M1, the overall power remaining the same, then the overall efficiency is improved, which represents a saving in energy consumption for the same overall power, compared with injecting power via the second motor M2.
Thus, as a function of the nature of the natural gas being produced from the underground reservoirs, both in terms of quantity and in terms of quality, it is advantageous to use a gas turbine GT, e.g. a 25 MW gas turbine, continuously at full power with power being added, and where appropriate modulated, by:
In a first variant of the process, two compressors are used that are connected in series, and that comprise:
i) at least one first compressor, preferably a said first compressor coupled to said first expander compressing from P1 to P2 all of said first stream of refrigerant gas leaving said first heat exchanger; and
ii) at least one second compressor, preferably a said second compressor coupled to said second expander, compressing firstly said third stream of refrigerant gas leaving said first heat exchanger at P2 and secondly said first stream of refrigerant gas compressed to P2 and leaving said first compressor, from P2 to at least P′3, where P′3 is higher than P2 and lower than or equal to P3, in order to obtain said second stream of refrigerant gas at P3 and T0 after cooling; and
iii) said first compressor being driven by a first motor, said second compressor being driven by at least one said gas turbine.
This first variant implementation is advantageous in that it makes it possible to provide an installation that is more compact in terms of the amount of space occupied on board the floating support.
In a second variant implementation, use is made of three compressors connected in series, the compressors comprising:
i) a first compressor driven by a first motor and coupled to said first expander, compressing from P1 to P2 all of said first stream of refrigerant gas leaving said first heat exchanger; and
ii) a second compressor driven by a second motor and coupled to said second expander compressing firstly said third stream of refrigerant gas leaving said first heat exchanger at P2 and secondly said first stream of refrigerant gas compressed to P2 and leaving said first compressor from P2 to P′3, where P′3 is higher than P2 and lower than P3; and
iii) a third compressor driven by a said gas turbine to supply the major portion of the energy and to compress from P′3 to P3 all of the first and third streams of refrigerant gas compressed by the second compressor in order to obtain said second stream of refrigerant gas at P3 and T0 after cooling; and
iv) said first motor delivers at least 3%, and more preferably at least 3% to 30%, of the total power delivered to all of said compressors in use, the gas turbine coupled to said third compressor and said second motor coupled to the second compressor together supplying 97% to 70% of the total power delivered to all of said compressors in use.
This second variant implementation is advantageous in terms of thermodynamic efficiency and in terms of production capacity since it is then advantageously possible to use a gas turbine having the maximum capacity that is available on the market, i.e. lying in the range 25 MW to 30 MW for gas turbines designed to be installed on board a floating support, together with a second electric motor, e.g. having power of 5 MW to 10 MW that is connected to the second compressor, the total power available from the second motor plus the third motor (the gas turbine) then lying in the range 30 MW to 40 MW, and thus being considerably higher than the power available from the largest gas turbine available on the market and suitable for use on board floating supports. Advantageously, the second motor may also be a gas turbine, preferably of power identical to the main gas turbine, thus making it possible to reach an overall power level of 50 MW to 60 MW.
By varying the pressure P2 by delivering energy to said first compressor via said first motor, the process of the invention makes it possible to use a minimum amount of total energy Ef consumed in the process that is lower than 21.5 kW×d/t, and more particularly that lies in the range 18.5 kW×d/t to 20.5 kW×d/t of liquefied gas production.
In general, a gas turbine GT will be operated at full power, and additional power will be delivered via the first motor M1, said additional power delivery being limited to lower than 30% of the total power so as to optimize efficiency at the minimum value lying in the range 18.5 kW×d/t to 21.5 kW×d/t, and then where necessary, the overall power can be increased by injecting power via the second motor M2, and concurrently the power injected via the first motor M1 should be readjusted so that said power is always substantially equal to less than 30% of the overall power so as to conserve the efficiency of the installation at the optimum power in the range 18.5 kW×d/t to 21.5 kW×d/t.
Said optimum efficiency of 19.75 kW×d/t can be obtained for the first motor M1 delivering 24% of the total power when the refrigerant fluid is constituted by 100% nitrogen. When using other gases such as neon or hydrogen or nitrogen-neon or nitrogen-hydrogen mixtures, the power percentage and the optimum efficiency vary in the range 18.5 kW×d/t to 21.5 kW×d/t depending on the gas or the mixture and on the percentages of neon or hydrogen, but the advantages specified above remain valid and can even be cumulative.
More particularly, said refrigerant as comprises nitrogen.
In a variant implementation, said refrigerant gas consists in a single gas selected from nitrogen, hydrogen, and neon.
Neon is preferred because of the greater risk of explosion with hydrogen and because hydrogen can present a certain propensity for percolating through elastomer gaskets and even through thin metal walls.
According to other particular characteristics:
The present invention also provides an installation on board a ship or a floating support for implementing a process of the invention and characterized in that it comprises:
Still more particularly, a said installation comprises:
only at least two compressors connected in series and comprising:
i) at least one said first compressor coupled to said first expander, suitable for compressing from P1 to P2 all of said first stream of refrigerant gas leaving said first heat exchanger; and
ii) at least a second compressor coupled to said second expander, suitable for compressing from P2 to P3 firstly said third stream of refrigerant gas leaving said first heat exchanger at P2 and secondly said first stream of refrigerant gas compressed to P2 and leaving said first compressor, in order to obtain said second stream of refrigerant gas at P3 and T0 after cooling; and
iii) a said first motor coupled to a said first compressor, and a gas turbine coupled to a second compressor, said first motor being suitable for delivering at least 3%, more preferably 3% to 30%, of the total power delivered to all of said compressors in use; and
iv) said gas turbine coupled to said second compressor being suitable for supplying 97% to 70% of the total delivered power.
Still more particularly, an installation of the invention comprises:
only three compressors connected in series and comprising:
i) a said first compressor coupled to said first expander and to a said first motor; and
ii) a said second compressor coupled to said second expander and to a said second motor; and
iii) a third compressor coupled to a gas turbine suitable for supplying the major portion of the energy and suitable for compressing to P3 all of the first and third streams of refrigerant gas compressed by said second compressor in order to obtain said third stream of refrigerant gas at P3 and T0 after cooling; and
iv) said first motor being suitable for delivering at least 3%, more preferably 3% to 30%, of the total power delivered to all of said compressors in use, the gas turbine coupled to said third compressor and said second motor coupled to the second compressor being suitable together for supplying 97% to 70% of the total power delivered to all of said compressors in use.
Other characteristics and advantages of the present invention appear in the light of the following detailed description of embodiments given with reference to the accompanying figures, in which:
Heat exchangers of this type are known to the person skilled in the art and they are sold by the suppliers Linde (France) or Five Cyrogénie (France). Thus, all of the circuits of a cryogenic heat exchanger are in thermal contact with one another in order to exchange heat, but the fluids that flow through them do not mix. Each of the circuits is dimensioned so as to minimize head losses at the maximum flow rate of the refrigerant fluid and so as to present sufficient strength to withstand the pressure of said refrigerant fluid as it exists in the loop in question.
In conventional manner, an expander causes the pressure of a fluid or a gas to drop and is represented by a symmetrical trapezoid, its small base representing its inlet 10a (high pressure) and its large base representing its outlet 10b (low pressure) as shown in
In the same way, and in conventional manner, a compressor increases the pressure of a gas and is represented by a symmetrical trapezoid, with its large base representing the (low pressure) inlet 11a and its small base representing the (high pressure) outlet 11b, as shown in
Natural gas flows in the circuit Sg and enters at AA into the first cryogenic heat exchanger EC1 at a temperature T0, higher than or substantially equal to ambient temperature, and exits at T1=−50° C. approximately. In this heat exchanger EC1, the natural gas is cooled but it remains in the gaseous state. At BB it passes into the cryogenic heat exchanger EC2 in which temperature extends over the range T1=−50° C. approximately, to T2=−120° C. approximately.
In this heat exchanger EC2, all of the natural gas liquefies into LNG at a temperature of T2=−120° C., approximately, and then the LNG passes at CC into the cryogenic heat exchanger EC3. In this heat exchanger EC3, the LNG is cooled down to the temperature T3=−165° C., which enables the LNG to be discharged from the bottom portion at DD, and then to be depressurized at EE so that the liquid can finally be stored at ambient atmospheric pressure, i.e. at an absolute pressure of 1 bar (i.e. about 0.1 megapascals (MPa)). All along this path of the natural gas along the circuit Sg in the various heat exchangers, the natural gas cools, transferring its heat to the refrigerant gas, which then heats up and needs to be continuously subjected to a complete thermodynamic cycle for the purpose of continuously extracting the heat in the natural gas entering at AA.
Thus, the path of the natural gas is shown on the left of the PFD, and said gas flows downwards along the circuit Sg, its temperature decreasing going downwards from a temperature T0 that is substantially ambient at the top at AA, down to a temperature T3 of about −165° C. at the bottom at DD.
The right-hand portion of the PFD shows the double-loop thermodynamic cycle of the refrigerant gas corresponding to circuits S1 and S2. To clarify explanation, the pressure levels in the main circuits are represented by fine lines for low pressure (P1 in the circuit S1), by medium lines for intermediate pressure (P2), and by bold lines for high pressure (P3 in the circuit S2).
In a conventional circuit as shown in
The installation is made up of:
A cooler H1, H2 may be constituted by a water heat exchanger, e.g. a heat exchanger using sea or river water or using cold air, the heat exchanger being of the fan coil or cooling tower type, such as those used in nuclear power stations.
More precisely,
a) causing said natural gas for liquefying to flow Sg at a pressure P0 higher than or equal to atmospheric pressure (Patm), with P0 preferably being higher than atmospheric pressure, the gas flowing through the three cryogenic heat exchangers EC1, EC2, EC3 arranged in series and comprising:
b) causing a first stream S1 of refrigerant gas in the gaseous state and compressed to a pressure P1 lower than P3 to flow in a closed circuit in indirect contact with and as a countercurrent to the natural gas stream Sg, said first stream S1 at a pressure P1 passing through the three heat exchangers EC3, EC2, and EC1, entering at DD into said third heat exchanger EC3 at a temperature T3′ lower than T3 and then leaving said third heat exchanger and entering said second heat exchanger EC2 at CC at a temperature T2′ lower than T2, and then leaving the second heat exchanger and entering the first heat exchanger EC1 at BB at a temperature T1′ lower than T1, and leaving said first heat exchanger EC1 at AA at a temperature T0′ lower than or equal to T0;
c) said second stream S2 compressed to P3 is obtained by compression using three compressors C1, C2, and C3 followed by at least two coolers H1 and H2 acting on said first stream S1 of recycled coolant gas leaving said first heat exchanger EC1 at AA via a first compressor C1 coupled to said first expander E1; and
d) after step a), the liquefied natural gas is depressurized from the pressure P0 to atmospheric pressure.
More precisely, in
In
The refrigerant gas leaving the heat exchanger EC1 at the high outlet at AA from the circuit S1 has a flow rate D: it is at low pressure P1 and at a temperature T′ that is perceptibly lower than T0 and at ambient temperature. It is then compressed in C3 to the pressure P′3, after which it passes through a cooler H1. The fluid at flow rate D is then split into two portions presenting flow rates D1′ and D2′ that are fed respectively to the compressors C1 (D1′) and C2 (D2′) that are operating in parallel. The two streams at the pressure P3 are then reunited and then cooled substantially to ambient temperature T0 by passing through the cooler H2. This total flow then enters into the top of the cryogenic heat exchanger EC1 via the circuit S2, and then at the outlet from the first level at BB, a large portion of the stream at flow rate D2 (D2 greater than D1) is extracted and directed to the turbine E2 coupled to the compressor C2. The remainder of the flow D1 passes through the second stage of the cryogenic heat exchanger EC2, and then at CC it is directed to the turbine E1 coupled to the compressor C1.
At the outlet from the turbine E1, the refrigerant gas at a temperature T3′ lower than T3=−165° C., is then directed downwards from the cryogenic heat exchanger EC3 into the circuit S1 and rises as a countercurrent to the gas for liquefying that is flowing along the circuit Sg, thereby performing the final stage 3 of the liquefaction.
The flow D2 of refrigerant gas coming from the turbine E2 is at a pressure P1 and at a temperature T2 of about −120° C. and it is recombined within the circuit S1 with the flow D1 coming from the turbine E1 via the top outlet from the cryogenic heat exchanger EC3 at CC.
The separation of the second stream S2 into two portions having different flow rates D1 and D2 at the outlet BB from the first heat exchanger, preferably with D2 greater than D1, is advantageous since most of the energy consumption takes place during stage 2 within the second heat exchanger EC2. Thus, only a minor portion of the flow rate D1 passes through the third heat exchanger EC3 where stage 3 takes place, while the total flow D=D1+D2 of the circuit S1 passes through the cryogenic heat exchanger EC2 in order to perform liquefaction stage 2 (from temperature T1=−50° C. to T2=−120° C.)
The same flow D of the circuit S1 finally passes through the cryogenic heat exchanger EC1 in order to perform stage 1 of the liquefaction process (from temperature T1=−50° C. to temperature T0=ambient temperature). At the top outlet from the cryogenic heat exchanger EC1, the flow D of the circuit S1 is at the temperature T0′ that is perceptibly lower than ambient temperature. Thereafter, the flow D is once more directed to the compressor C3 in order to perform a new cycle in continuous manner.
In this configuration, the compressors C1 and C2 run in parallel and they need to provide the highest pressure level in the cycle. The two compressors C1 and C2 handle different flow rates of refrigerant fluid, respectively D1′ and D2′, and they are directly coupled to the turbines E1 and E2, which likewise handle different flow rates, respectively D1 and D2.
The following relationship applies:
D1+D2=D=D′1+D′2
where D1 is different from D′1 and D2 is different from D′2. In practice, and preferably D1/D=5% to 35%, and preferably 10% to 25%.
Thus, in that type of installation, all of the power is injected into the system via the compressor C3 (by the gas turbine GT), with the power transfers via the turbine and compressor pairs E2-C2 and E1-C1 varying as a function of the pressures in the various circuits (P1, P2, P3), as a function of the temperature levels at the inlets to the cryogenic heat exchangers, and as a function of the heat transfers within each of said cryogenic heat exchangers.
Thus, such an installation presents an operating point that self-stabilizes at a given level of energy consumption Ef which is generally expressed in terms of kW×d/t, i.e. kW-days per tonne of LNG produced, or indeed kWh per kg of LNG produced, said operating point possibly being totally unstable in certain circumstances. It is then very difficult to control the pressures in the high and low pressure loops independently of each other. This may be found to be necessary in the event of variations in the composition of the natural gas for liquefying. It is possible to modify the streams by locally constraining the flows D1, D′1, D2, D′2 in full or in part, e.g. by creating localized head losses, however such arrangements lead to losses of energy and thus to a drop in the overall efficiency of the liquefaction installation.
The graph of
The graph shows:
Curve 50 made up of triangles shows the variations in the enthalpy H of the fluids flowing as cocurrents in the circuits Sg and S2 as a function of the temperature of the gas for liquefying comprising methane and/or LNG for an ideal virtual process.
The curve 51 corresponds to the variation in the enthalpy H of the refrigerant gas flowing in the circuit S1 of
The area 52 lying between the two curves 50 and 51 represents the overall loss of the energy Ef consumed in the liquefaction process: this area should therefor be minimized in order to obtain the best efficiency. In land-based processes involving a change of phase in the refrigerant fluid, the curve 51 is not straight, but rather comes close to the theoretical curve 50, thereby implying smaller losses, and thus better efficiency, but the process with a change of phase in the refrigerant fluid is not suitable for use in liquefaction on board a floating support and in an environment that is confined.
In
Because the major portion of the energy is consumed in stage 2 of the process within said second heat exchanger, this makes it possible to further increase the transfers of heat and the overall energy efficiency of the process. However, and more importantly, this also makes it possible to modulate and control specifically the value of the pressure P2 by connecting the two compressors C1 and C2 in series and by coupling C1 with a motor M1 serving to modulate and control the additional power delivered to C1, which is already coupled to the turbine E1, thus making it possible to control the pressure value P2 as described below.
More precisely,
a) causing said natural gas for liquefying to flow Sg at a pressure P0 higher than or equal to atmospheric pressure (Patm), P0 being higher than atmospheric pressure, through three cryogenic heat exchangers EC1, EC2, EC3 connected in series and comprising:
b) causing refrigerant gas in the gaseous state to flow in a closed circuit in two streams S1 and S3, referred to respectively as the first and third streams, having respective different pressures P1 (S1) and P2 (S2), the streams passing through two of said heat exchangers in indirect contact with and as a countercurrent to the natural gas stream Sg, the streams comprising:
c) said second stream of refrigerant gas S2 compressed to the pressure P3 being obtained by compressing said first and third refrigerant gas streams leaving said first heat exchanger EC1 at AA and respectively at P1 and P2 by means of first and second compressors respectively C1 and C2 connected in series and coupled respectively to said first and second expanders E1 and E2, which are constituted by turbines; and
d) after step a), the liquefied natural gas leaving said third heat exchanger at DD and at T3 is depressurized from the pressure P0 to atmospheric pressure, where appropriate.
More precisely, in
1) three compressors C1, C2, and C3 connected in series and comprising:
2) said first compressor C1 is coupled to a first motor M1 serving to vary the pressure P2 in controlled manner by delivering power in controlled manner to said first compressor C1, said first motor M1 delivering at least 3%, and preferably 3% to 30%, of the total power delivered to all of said compressors C1, C2, and C3 that are in use, the gas turbine GT coupled to said third compressor C3 and the second motor M2 coupled to the second compressor C2 together delivering 97% to 70% of the total power delivered to all of said compressors C1, C2, and C3 that are in use.
The installation of
The compressors C1 and C2 are connected in series:
The entire refrigerant gas flow D leaving the compressor C2 is cooled in a cooler H1 prior to returning to the pressure P′3 in the compressor C3, which compressor is connected to a motor (GT) generally a gas turbine. Said gas turbine and the motor (M2) together delivering 70% to 97% of the total power Q to the refrigerant gas, with the balance of the power being delivered to the system via the motor M1, i.e. 30% to 3% of the total power Q.
At the outlet from the compressor C3, all of the refrigerant gas flow D is at the high pressure P3. The stream is then cooled in a cooler H2 prior to flowing in the circuit S2 downwards through two of the cryogenic heat exchangers EC1 and EC2.
The fraction D2 of the refrigerant gas stream is taken at BB from the outlet from the cryogenic heat exchanger EC1 and is directed to the inlet of the turbine E2, the balance, i.e. the fraction D1 of the refrigerant gas stream being taken at CC from the outlet from the cryogenic heat exchanger EC2 and being directed to the inlet of the turbine E1.
A cooler H2 operating at a pressure P′3 is installed within the compressor C3 between two compression stages, said cooler H2 handling all of the flow D.
In this process of the invention, the following relationships apply:
D1+D2=D
and preferably D1/D2=1/3 to 1/20, and more preferably 1/4 to 1/10.
The main advantage of the device of the invention as shown in
Thus, in the graph of
The curve 53 corresponds to the variation in the enthalpy H of the refrigerant fluid flowing in the circuits S1 and S3 of
The area 52 lying between the two curves 50 and 53 represents the overall energy loss in the liquefaction process with reference to
During variations over time in the quantity of natural gas delivered by the gas field, and thus of its composition, the low point 54 of the curve 50 corresponding to P0 and T2 at the end of liquefying the LNG may vary by a few percent. In the conventional process of
In contrast, in the device of the invention as shown in
In this version of
In
Furthermore, in
The points W0 to W4 correspond to the following powers being injected via the motor M1:
W0=zero power;
W1=7% of the total power;
W2=15% of the total power;
W3=24% of the total power; and
W4=33% of the total power.
In similar manner, the diagram of
Thus, in this same
In similar manner in the diagram of
Thus, an increase in the proportion of the power W injected via the motor M1 in
In the same way, the use of a nitrogen-neon mixture leads to an improvement in energy performance as shown in
Thus, giving consideration to a mixture having 20% neon, the pressure P1 is about 12.5 bars and curve 71 in
For this same neon percentage of 20%, curve 91 of
The same effects are observed using hydrogen, as can be seen in
In
In the diagram of
In general, by operating at higher pressure, for a given mass flow rate, the volume flow rates are reduced prorata the increase in said pressure: the pipes are thus of smaller diameter, while their mechanical strength and thus their thickness, their weight, and their cost need to be increased accordingly: in contrast, the footprint is also reduced accordingly, which is most advantageous for installations in a confined environment, such as on a floating support anchored at sea, or indeed on a methane tanker for a unit for reliquefying boil-off. In the same manner, compressors and turbines operating at higher pressures are much more compact. For the cryogenic heat exchangers, an increase in pressure also improves heat transfer, but the heat exchange areas are not reduced by as much as for the pipes and the compressors and the turbines. In contrast, their weight increases significantly because they need to be able to withstand this increase in pressure.
Thus, overall, the process of the invention as shown in
Thus, for a given gas composition, the operating point of the conventional process described with reference to
By using a mixture of 80% nitrogen and 20% neon as the refrigerant gas, it is possible to increase pressure, as shown by curve 70, without the gas mixture reaching its dew point up to an optimum value 70a of about 88 bars and for an energy consumption of about 19.4 kW×d/t, which represents a thermodynamic efficiency improvement of 1.77% compared with the operating point 62 of the process of the invention with a refrigerant gas made up of 100% nitrogen and a thermodynamic efficiency improvement of 8.92% compared with the operating point 60 of the conventional process.
By using a 60% nitrogen and 40% neon mixture as the refrigerant gas, it is possible to increase pressure as shown by curve 71 without the gas mixture reaching its dew point up to an optimum value 71a of about 118 bars, together with minimum energy consumption of about 19.15 kW×d/t, which represents a thermodynamic efficiency improvement of 3.04% compared with the operating point 62 of the process of the invention with a refrigerant gas made up of 100% nitrogen, and a thermodynamic efficiency improvement of 10.09% compared with the operating point 60 of the conventional process.
By using a mixture of 50% nitrogen and 50% neon as the refrigerant gas, it is possible to increase the pressure, as shown by curve 72, without the gas mixture reaching its dew point, up to an optimum value 72a of about 145 bars in association with minimum energy consumption of about 18.8 kW×d/t, which represents a thermodynamic efficiency improvement of 4.81% compared with the operating point 62 of the process of the invention with a refrigerant gas made up of 100% nitrogen, and a thermodynamic efficiency improvement of 11.74% relating to the operating point 60 of the conventional process.
In the same manner, as shown in the diagram of
Thus, by using a mixture of 80% nitrogen and 20% hydrogen as the refrigerant gas, it is possible to increase the pressure as shown by curve 80 without the gas mixture reaching its dew point up to an optimum value 80a of about 94 bars associated with minimum energy consumption of about 19.2 kW×d/t, which represents a thermodynamic efficiency improvement of 2.78% compared with the operating point 62 of the process of the invention of
By using a 60% nitrogen and 40% hydrogen mixture as the refrigerant gas, it is possible to increase the pressure, as shown by curve 81, and without the gas mixture reaching its dew point, up to an optimum value 81a of about 140 bars in association with minimum energy consumption of about 18.8 kW×d/t, which represents a thermodynamic efficiency improvement of 4.81% compared with the operating point 62 of the process of the invention as shown in
As shown by curve 82, by using a mixture of 50% nitrogen and 50% hydrogen as the refrigerant gas, it is possible to increase the pressure without the gas mixture reaching its dew point up to an optimum value 82a of about 186 bars, in association with minimum energy consumption of about 18.7 kW×d/t, which represents a thermodynamic efficiency improvement of 5.32% compared with the operating point 62 of the process of the invention of
Thus, for an increasing percentage of the additional gas, whether hydrogen or neon, that is added to nitrogen in order to make up the refrigerant gas, the thermodynamic efficiency of the process is significantly improved, while allowing operation at higher pressure, which implies equipment that is more compact, which in itself is most advantageous when only very small areas are available, as applies to a floating support anchored at sea or on board a methane tanker when applied to reliquefaction units.
The process of the invention uses either a mixture of nitrogen and neon or of nitrogen and hydrogen, and in spite of its slightly lower efficiency, it is preferred to use the nitrogen and neon mixture, since neon is an inert gas, whereas hydrogen is combustible and remains dangerous and difficult to use, in particular at high pressure in confined installations on board a floating support. In addition, hydrogen is a gas that percolates very easily through elastomer gaskets and even under certain circumstances through metals, particularly at very high pressure, and as a result the process of the invention based on the use of a nitrogen-hydrogen mixture does not constitute the preferred version of the invention: the preferred version of the invention remains using a mixture of nitrogen and neon as the refrigerant gas in the devices described above with reference to the various figures.
In the same manner, the efficiency of conventional processes using nitrogen as the refrigerant gas can be improved by giving consideration to a binary mixture of nitrogen and neon or of nitrogen and hydrogen.
Thus, as shown in the diagram of
With a 40% neon content, the operating point is situated at 71b, which corresponds to a maximum pressure P3 of about 90 bars and to energy consumption of about 19.70 kW×d/t, which represents a thermodynamic efficiency improvement of 7.29% compared with the operating point 60 of the process conventional process with a refrigerant gas made up of 100% nitrogen.
For a 50% neon content, the operating point is situated at 72b, which corresponds to a maximum pressure P3 of about 120 bars and to an energy consumption of about 19.35 kW×d/t, which represents a thermodynamic efficiency improvement of 8.94% compared with the operating point 60 of the same conventional process using a refrigerant gas made up of 100% nitrogen.
In the same manner, with a nitrogen-hydrogen mixture having 20% hydrogen, as shown in
For a 40% hydrogen content, the operating point is situated at 81b, which corresponds to a maximum pressure P3 of about 108 bars and to energy consumption of about 19.8 kW×d/t, which represents a thermodynamic efficiency improvement of 6.82% compared with the operating point 60 of the same conventional process with a refrigerant gas made up of 100% nitrogen.
With a 50% hydrogen content, the operating point is situated at 82b, which represents a maximum pressure P3 of about 150 bars and an energy consumption of about 19 kW×d/t, which represents a thermodynamic efficiency improvement of 10.59% compared with the operating point 60 of the same conventional process with a refrigerant gas made up of 100% nitrogen.
By way of example, a conventional liquefaction unit is dimensioned with reference to the powers of available gas turbines, and high power turbines commonly deliver 25 MW.
In general, it is desired to increase the power of the installation so it is possible to install two identical gas turbines (GT1 and GT2) in parallel in order to obtain 30 MW (2×15 MW) or indeed 40 MW (2×20 MW), however there are then two rotary machine lines which increases overall bulk, the amount of pipework, and naturally costs.
By using a single 25 MW gas turbine GT at C3 as in
Thus, giving consideration to a 25 MW gas turbine GT, and adding 5 MW via the motor (M2), preferably using an electric motor, gives greater flexibility in operation and thus makes it possible to increase power by 20%. In contrast, the overall efficiency remains unchanged being substantially 21.25 kW×d/t of LNG produced, as shown in the diagram of
In contrast, if the same power of 5 MW is delivered via the first motor M1, the overall power is still 30 MW, but the overall efficiency is then improved, substantially reaching the value of 19.8 kW×d/t of LNG produced, which represents an improvement of 6.59% for the same overall power of 30 MW, compared with injecting a power of 5 MW via the second motor M2, as described above. Said additional 5 MW of power via the first motor M1 then represents 16.6% of the overall power and said efficiency (19.8 kW×d/t) corresponds substantially to the point W2 in the diagram of
In the same manner for the embodiment of
Thus, in consideration of a 25 MW gas turbine GT, adding 5 MW of power via the turbine GT gives greater flexibility in operation and thus enables power to be increased by 20%. In contrast, the efficiency of the assembly remains unchanged, being substantially 21.25 kW×d/t of LNG produced, as shown in the diagram of
In contrast, if the same power of 5 MW is delivered via the first motor M1, the overall power is still 30 MW, but the overall efficiency is then improved and reaches a value of substantially 19.8 kW×d/t of LNG produced, which represents an improvement of 6.59% for the same overall power of 30 MW, compared with injecting power, of 5 MW via the second motor M2 as described above. Said additional 5 MW of power added via the first motor M1 then represents 16.6% of the overall power and said efficiency (19.8 kW×d/t) corresponds substantially to the point W2 in the diagram of
Thus, as a function of the quantities and the qualities of the natural gas produced from underground reservoirs, it is advantageous to use a gas turbine GT, e.g. a 25 MW turbine, that operates continuously at full power:
In general, a gas turbine GT will be used at full power, and additional power will be delivered via the first motor M1, said additional power being limited to about 24% of the overall power so as to optimize the efficiency on the minimum value of 19.75 kW×d/t, and then, where necessary, the overall power will be increased by injecting power via the second motor M2 and concurrently readjusting the power injected via the first motor M1 so that the power it injects is still substantially equal to about 24% of the total power so as to conserve the efficiency of the installation on the optimum value of 19.75 kW×d/t.
Said optimum efficiency of 19.75 kW×d/t for power from the first motor M1 representing 24% of the total power is valid for a refrigerant fluid constituted by 100% nitrogen. When using a nitrogen-neon or nitrogen-hydrogen mixture, the optimum efficiency, and thus also the power percentage vary as a function of the mixtures and of their percentages of neon or hydrogen, but the advantages described in detail above remain valid and are even cumulative.
| Number | Date | Country | Kind |
|---|---|---|---|
| 11 55595 | Jun 2011 | FR | national |
| Filing Document | Filing Date | Country | Kind | 371c Date |
|---|---|---|---|---|
| PCT/FR2012/051428 | 6/22/2012 | WO | 00 | 12/19/2013 |
| Publishing Document | Publishing Date | Country | Kind |
|---|---|---|---|
| WO2012/175889 | 12/27/2012 | WO | A |
| Number | Name | Date | Kind |
|---|---|---|---|
| 20100122551 | Roberts et al. | May 2010 | A1 |
| 20100257895 | Balling et al. | Oct 2010 | A1 |
| 20100263405 | Durand | Oct 2010 | A1 |
| 20110113825 | Neeraas | May 2011 | A1 |
| Number | Date | Country |
|---|---|---|
| 2 336 677 | Jun 2011 | EP |
| WO 2005071333 | Aug 2005 | WO |
| Entry |
|---|
| Skjeggedal et al. “Optimising and Scaling Up the Brayton Nitrogen Refrigeration Cycle for Offshore and Onshore LNG Applications”, 2009, Hamworth Gas Systems AS, The 24th International Conference and Exhibition for the LNG, LPG, and natural gas industries, May 25-28, 2009, Abu Dhabi, pp. 1-18. |
| Olve Skjeggedal et al: “Optimising and Scaling up the Brayton Nitrogen Refrigeration Cycle for Offshore and Onshore LNG Applications”, Gastech 2009. The 24th International Conference and Exhibition for the LNG, LPG and natural Gas Industries, May 25-28, 2009, Abu Dhabi, p. 18 XP009144463. |
| Number | Date | Country | |
|---|---|---|---|
| 20140190205 A1 | Jul 2014 | US |
