The present invention relates to a method and an apparatus for cooling a hydrocarbon stream. In particular it relates to a method wherein the hydrocarbon stream comprises natural gas and wherein the natural gas is cooled to liquefaction, yielding liquefied natural gas (LNG).

BACKGROUND OF THE INVENTION

Methods for cooling hydrocarbons to form liquefied natural gas to obtain more convenient forms for transportation and storage are well known. Liquefied natural gas may be produced in single and multi stage liquefaction processes for both single and mixed refrigerants as well as combinations of refrigerants in (1 ) "cascade cycle" which uses heat exchangers arranged progressively to reduce the temperature of the gas to a liquefaction temperature, (2) "expander cycle" which expands gas from a high pressure to a low pressure with a corresponding reduction in temperature, and (3) "multi-component refrigeration cycle" which uses a multi-component refrigerant in heat exchangers. Where two or more refrigerant circuits are employed the respective circuits may cool and condense the natural gas stream in series, in parallel or in a cascade arrangement where one refrigerant circuit is used to cool a second refrigerant, which in turn cools the natural gas stream.

Any LNG liquefaction process requires some, e.g., one, two or three, refrigerant cycles using various refrigerant gases to cool natural gas down to -162 ^° C utilizing a main cryogenic heat exchanger or cold-box where methane liquefies. Refrigerant gases that have been used include propane, propylene, ethane, ethylene, methane, butane, nitrogen, carbon dioxide, or combinations of the preceding refrigerants ("mixed refrigerant systems"). The size, number and types of the refrigerant cycles determine the efficiency and cost of different liquefaction processes. Each cycle takes relatively warm, pre-treated feed gas and cools it till it condenses into LNG product. To produce the cold temperatures required to produce LNG, work must be put into the cycle through a refrigerant compressor and heat must be rejected from the cycle through (e.g. air or water) coolers. The amount of work (which depends on the size of refrigerant compressors, the efficiency of the compressor and drivers and refrigerant flow rate) is a function of the liquefaction process, the feed gas conditions and the required delta in temperature. Commonly, before hydrocarbonaceous natural gas is cooled it is treated to remove compounds such as ammonia, hydrogen sulphide and carbon dioxide. Usual treatments include absorption in an amine-containing solution. Subsequently, the natural gas is cooled. During the cooling process other constituents of the feed gas with higher boiling points are removed. These constituents may include remaining water, carbon monoxide, carbon dioxide, but also ethane, propane, butane and heavier hydrocarbons. Also nitrogen is removed as this inert gas lowers the heating value of LNG. Ultimately the product of the liquefaction process is predominantly liquefied methane.

Over the years liquefaction plants have increased in size. These larger plants with more refrigerant cycles have become more complex and more costly to build. Amongst the economic considerations that are of importance in the design and operation of a liquefaction plant, the capital expense, the operating expense, and the availability are key. By

"availability" is understood the time that the plant is producing hydrocarbons. By

hydrocarbons are understood both LNG and heavier hydrocarbons, also known as condensates. LNG plants may be onshore or offshore. Offshore plants, also called floating LNG plants, are being developed for exploitation of remote gas fields at sea.

Different types of compressors are used in industry like axial, centrifugal and positive displacement compressors. In LNG liquefaction plants typically centrifugal and axial compressors are utilized. Axial compressors are typically utilized for process duties requiring a high flow and relative narrow flow operating range. Despite its lower efficiency are centrifugal compressors more commonly utilized due to its wider operating range.

The vast majority of LNG plants use single cycle heavy-duty gas turbines to drive one or more refrigerant compressors. Other plant designs use steam turbines or motor drivers. Combinations of these turbines and drivers may also be used. Outages of the turbines and/or drivers cause a major portion of the production losses due to scheduled and unscheduled outages and output reduction due to fouling, degradation and temperature de-rating. Turbine driven compression trains currently cause a disproportional share of the total production losses.

With increase in size of LNG plants, compression duty has been split and/or placed in parallel to obtain certain liquefaction train size. Use of large heavy duty gas turbines with configurations of two or three compressor trains in parallel has resulted in very large single LNG liquefaction plants. Often a "carbon copy" plant is built alongside to expand capacity at a location.

Typical LNG liquefaction train availability is in the order of 95-98% due to scheduled and unscheduled outages of the liquefaction compressors and associated drivers. The typical average LNG plant uptime is in the order of 92 to 96% and leaves room for improvement.

Parallel compressor trains configurations are sometimes used, typically when a single turbine or driver is too small for a specific duty or plant size. A 100% compression train can be replaced by 2x50% or 3x33% or 4x25% or Nx100%/N etc. units to obtain that same capacity or 3 x 50% or 4x33% or 5x25% or (N+1 )x100%/N etc, when incorporating a spare unit. A spare unit is utilized to maintain 100% capacity at the outage of one unit.

An LNG plant is typically designed such that the maximum capacity of the heat exchanger is bigger than the compression duty. In view of the increasing size of LNG plants, the compression duty is typically provided by so-called heavy duty gas turbines. These are designed to operate at substantially constant maximum speed and, thus, at their maximum capacity. Since the capacity of these turbines is the lowest, they are required to operate at their maximum to make the LNG plant run as effectively as possible. Although the constant speed of the turbines facilitates the operation of the compression unit, it has disadvantages with respect to the operation and capacity of the heat exchanger.

A compressor, commonly operated via a driver, is characterized by its ability to produce a certain increase in pressure rise over a certain gas flow of certain gas composition at certain inlet conditions. The shaft power required to perform a compression duty is proportional to the head and the mass flow. An increase in head and/or mass flow over a compressor hence requires an increase in required power.

The skilled person knows that the minimum power required to produce a specific required head on a specific required mass flow of gas is obtained at the highest compressor efficiencies. This point is called the design capacity of a compressor or 100% capacity. The skilled person will realise that the design capacity is determined at a certain ambient temperature. When the environment would become colder the actual capacity of the compressor will increase, whereas at higher ambient temperatures the actual capacity will decrease.

US 2007/0193303 describes a modular LNG production plant with process unit modules that are sized at their respective substantial maximum processing efficiency.

According to US 2007/0193303 a traditional LNG train is designed to operate at a selected natural gas feed processing rate and normally not designed to operated at significantly reduced natural gas processing rates. The process of US 2007/0193303 employs a plurality of process unit modules. The specification also defines a maximum feed processing capacity for the process unit modules. That applies for instance to the compression units and the heat exchanger in the LNG plant. At increasing plant sizes, it is recommended to design more pieces of equipment, for example 2x50%, 3x33%, 4x25%, etc, or 3x50%. 4x33%, 5x25% etc. if an installed spare is used.

If this recommendation would be followed with respect to the maximum processing capacity for compression units it would mean that each would be designed to provide compressed refrigerant equal to 100%/N, with N being the number of compression units, of the maximum feed processing capacity of the heat exchanger. An identical compression unit could be used as spare in case of a shut down of one of the other units. The spare is not in operation when the others are.

US 6,647,744 discloses a method for LNG production utilizing parallel compressors in a utility. This patent emphasizes the benefits of adding one or more parallel units when increasing a LNG plant capacity. US 6,647,744 teaches that a single spare compression string can be installed to supply refrigerant to the different trains in the LNG plant to back up any of the other compression strings that supply refrigerant to the LNG plant. By switching to a back-up compression string the cryogenic heat exchange system can be kept cold during repair of the failing compressor string.

It is evident that the spare compression string in the LNG plant of US 6,647,744 is kept idle until one of the other compression strings fails.

The availability may also be hampered by the turn-down ratio. This turn-down ratio is defined as the ratio of the minimum flow of the refrigerant, when the plant has to be shut down, to the maximum flow of the refrigerant. This is also illustrated by US 2007/0193303 defining the "plant maximum feed processing capacity" as the maximum feed processing capacity of the entire LNG plant and the "plant minimum feed processing capacity" as the minimum feed processing capacity of the LNG plant wherein the plant can be run in a stable mode. This ratio is influenced by limitations of the heat exchanger design (e.g., pressure margin) and by the refrigerant compressor design. This causes a limitation to the amount of refrigerant that can go through the heat exchanger and thus the quantity of LNG the heat exchanger can produce. Given the limited pressure margin and safety requirements, the heat exchanger should not be operating at pressures significantly over its design conditions. The refrigerant inlet flow can be managed by controlling the flow, suction pressure and discharge pressure from the refrigerant compressors. The turn-down ratio of the heat exchanger can thus be defined as a percentage of refrigerant inlet flow as a percentage of the design capacity. A typical turn down ratio is 70%.

US 3,527,059 discloses a method for controlling parallel-operating refrigeration compressors. The objective is to make each compressor stage to operate efficiently at or near its normal capacity. Each stage of such compressor is designed to operate at 80% or more of its normal capacity. One of the objectives of this operation is to control the temperature of compressed refrigerant gases.

In US 4,057,972 a process for the liquefaction of natural gas has been described wherein a multi-component refrigerant system is used. The multi-component refrigerant system is a self-contained cycle. In addition the process employs an independent refrigeration system which is used to pre-cool the hydrocarbon feed gas to the stage that all potential solids have been removed. This process differs from the known so-called cascade refrigeration cycle, and has allegedly overcome the disadvantage that a cascade requires many compressors which is considered undesirable.

Neither US 3,527,059 nor US 4,057,972 addresses the problem of the availability of the LNG plant. US 2007/0193303 and US 6,647,744 describe operations wherein the availability of an LNG plant is improved by employing a processing unit that was available as a spare.

SUMMARY OF THE INVENTION

It has now been found that when at least two, preferably three or more compressors are used in parallel operation the availability and capacity of an LNG plant can be increased significantly, if the design capacity of the combined compressors is in excess of the maximum inlet flow of the refrigerant in the heat exchanger.

Accordingly, the present invention provides a method for cooling a hydrocarbon stream by passing the hydrocarbon stream through at least one heat exchanger, which method comprises the steps of:

(a) compressing a refrigerant in a compressor unit to yield compressed refrigerant;

(b) expanding the compressed refrigerant, to yield cold refrigerant;

(c) passing the hydrocarbon stream against the cold refrigerant in the heat exchanger having a maximum inlet flow of the refrigerant, to yield a cooled hydrocarbon stream and at least partly evaporated refrigerant;

(d) recovering the cold hydrocarbon stream; and

(e) recycling at least part of the at least partly evaporated refrigerant to the compressor unit, wherein the compressor unit comprises at least, preferably at least two, but preferably at least three, compressors that all operate simultaneously in parallel and wherein the compressor unit has a design capacity in excess of the maximum inlet flow of refrigerant to the heat exchanger.

The cold refrigerant in step (b) may partially comprise condensed refrigerant. The maximum inlet flow of refrigerant corresponds with the maximum feed processing capacity as defined in US 2007/0193303.

One of the advantages of the present invention over a configuration with a spare unit resides in a reduced capital expenditure. Further advantages will become apparent from the description below.

DETAILED DESCRIPTION

The present invention allows that when the LNG plant operates at normal capacity (e.g. design capacity) the compressors operate below design capacity. When one compressor has to be taken out for scheduled or unscheduled maintenance, repair, cleaning or a similar reason, the other, at least one but preferably two or more compressors will have sufficient capacity to provide an amount of refrigerant at sufficient pressure, temperature and flow rate to enable the LNG plant to operate above the turn down ratio. Hence, when one of the compressor units has to be switched off, there is no need to stop the production of LNG, which enhances the availability.

Further advantages of the present invention include that the heat exchanger may be operated at constant, maximum capacity. Such operation not only has the effect that the capacity of the plant will be at its maximum, but it also allows a constant operation of any equipment that is upstream or downstream of the heat exchanger. This will provide a simple monitoring and control system.

Further advantages of the present invention include the ability to operate longer periods near the compressor design point for optimum efficiency hence improving train efficiency and maintaining a high degree of operating flexibility (e.g. turndown from the compressor surge line).

A further advantage of the present invention includes the elimination of the need to change mixed refrigerant composition to match the change in seasonal and daily available power from the compressor driver plus the associated equipment related to controlling refrigerant composition.

The LNG liquefaction capacity is also influenced by the refrigeration medium. The boiling temperature and heat value of constituents and relative proportions of the gases of a (mixed or pure) refrigerant determine the temperature profile of the refrigerant and

hydrocarbon feed stream in the heat exchanger and hence on the efficiency and cooling capacity. Mixed refrigerants are more energy efficient as they display a gradual evaporation, opposed to pure refrigerants. Mixed refrigerant enters the refrigerant compressors with a temperature differential from its dew point to avoid the formation of liquids when entering the refrigerant compressors. It is know to the skilled person that this temperature differential is a limiting factor in the operating of refrigerant compressors (e.g. minimum refrigerant suction pressure and minimum suction temperature). Due to the fact that the design capacity of the compressor units is in excess of the maximum inlet flow of refrigerant of the heat exchanger, the reduction of the actual capacity of the compressor units, caused by higher temperatures of the environment than according to the design, can be overcome. It will be apparent that thereby the capacity of the heat exchanger can be fully utilized, also at higher environmental temperatures and at significant temperature differentials in the refrigerant.

The present invention improves LNG production capacity, availability, production efficiency and thermal efficiency of the compression trains in LNG liquefaction plants by installation of surplus compression capacity. As indicated above, that will enhance capacity at all feasible temperature ranges, but it can also compensate for equipment fouling, deterioration and derating. Further, it enhances availability by compensating compression outages. This is suitably achieved by installing two but preferably 3 or more compressors in a unit which can handle equal process conditions, such as gas composition, gas inlet temperature, pressure ratio, suction pressure and discharge pressure, and preferably identical capacity in terms of volumetric, mass or standard gas flow, that operate in parallel for one or more cryogenic heat exchangers that maybe configured in series and/or in parallel and/or in cascade configuration and/or a combination thereof. LNG plant designers can optimize additional cost of capital equipment by combining two or more distinct refrigerant compression duties (e.g., propane and mixed refrigerants) in this parallel compression train configuration.

The present invention can be applied in conjunction with heat exchangers in, in particular, LNG plants. As indicated above, these LNG plants may be onshore or offshore. Offshore plants, also called floating LNG plants, are being developed for exploitation of remote gas fields at sea. Especially for these expensive plants the improved availability obtainable with the present invention constitutes a significant advantage.

The capacity of an LNG plant is influenced by ambient air temperature. The power of a turbine is inversely proportional to ambient air temperature. If the heat sink temperature also varies, e.g., because the temperature of cooling water or cooling air goes up, the capacity of the LNG plant is further influenced. Typically, the equipment in an LNG plant is designed such that it can handle temperature variations, by applying standard design margins. The equipment in an LNG plant is typically slightly overdesigned for standard operating conditions.

The slight overdesign has as additional benefit in the present invention that the compressor would allow the compressors to operate at about 60 to 80% of their maximum capacity, thereby benefitting of advantages that were described in US 3527059. When one compressor is taken out for whatever reason, the other at least one compressor can be adjusted such that it or they operate at or near maximum capacity, thereby compensating at least partly for the taking out of the one compressor. In this way the availability and capacity of the LNG plant is improved.

The availability of an LNG plant is further improved since the capacity of the compressor units is increased beyond the maximum capacity of the heat exchanger, as expressed as the maximum inlet flow of refrigerant. In the context of the present application, the maximum capacity of the heat exchanger is expressed as the maximum flow of refrigerant that the heat exchanger can handle. The maximum flow of refrigerant already takes into account the design variations discussed above to cope with temperature variations. Additional refrigerant compression capacity is effectively an increment in refrigerant compressor flow to the heat exchanger. Therefore, the compressor unit has a capacity in excess of this maximum inlet flow of refrigerant of the heat exchanger. In this way the skilled person is enabled to operate at or near the standard design capacity of the heat exchanger even when one compressor has been taken out. Good results are obtainable when the compressor unit has a design capacity that is from 105 to 150%, preferably from 1 15 tot 150%, of the maximum inlet flow. If the excess capacity is below 105%, there is still a chance that temperature variations may become troublesome to operate above the turn down ratio. Such a risk is substantially avoided at an excess capacity above 105, even more so above 1 15%. At an excess capacity of above 150% the capital expense will become very high. Moreover, there is a chance that when all compressors are in operation, the compressors have to operate at a capacity of below 60 - 80% of their design capacity, which may lead to efficiency losses. In order to optimise the efficiency, the availability and the capital expenses, the number of compressors in the compressor unit suitably ranges from two to five, with three being particularly preferred. When there are more than one refrigerant compressor units, the excess capacity can be customised for each refrigerant compressor unit. Typically the design capacity of each compressor is the same, although the capacities of each compressor may suitably independently vary by 0 to 25 %.

The invention involves a number of advantages.

(a) It has now been found that when two but preferably three or more compressors are used in parallel, the availability of an LNG plant can be increased significantly beyond single and parallel compressor configurations with or without sparing, as the outage of one compressor would still enable a refrigerant flow that would be above the turn-down ratio by operating remaining units at maximum flow.

(b) It has also been found that under surplus upstream and downstream capacity conditions when two but preferably three or more compressors are used in parallel under normal operation with all units available, flow capacity of the compressor unit can increase well beyond 100% e.g. with 3x40% units (120%), 3x45% units (135%), 3x50% units (150%), 4x35% units (140%).

(c) It has also been found that typically under surplus upstream capacity conditions when one or two but preferably three or more compressors are used in parallel under normal operation, head capacity can increase substantially allowing a larger change in mixed or pure refrigerant gas composition.

(d) It has also been found that a compressor design can facilitate combinations of the above operating modes (a) till (c).

(e) It has also been found that it is easier to implement improved driver efficiency configurations in a compressor unit, utilizing a combination of one or more gas turbines ("GT"), one or more boilers (possibly equipped with supplementary firing for improved efficiency) and one or more steam turbines ("ST") in a compressor unit - as the total utility compression power inside one utility can be sized more flexible (e.g. 1 GT + 1 ST, 2 GT + 1 ST, 3 GT + 1 ST, 3 GT + 2 ST, with and without supplementary firing, etc) to suit a LNG plant size, whilst avoiding dependence of power requirements in a different compressor unit (e.g. when steam is generated in one compressor unit to drive steam turbines in a other compressor unit).

(f) It has also been found that LNG production capacity reduction can be reduced - utilizing a combination of gas turbines, boilers (possibly equipped with supplementary firing for improved efficiency) and steam turbines in multiple compressor units - when steam turbine duties of one unit are providing steam from gas turbine and boiler combinations at another unit, hence reducing the impact in plant LNG production capacity of a gas turbine outage.

The operation of an LNG plant is well known. The compressors are driven by one or more drivers. These drivers include gas turbines and/or steam turbines and/or electrical motors or reciprocating engines or a combination of these drivers. Accordingly, the compressors are coupled with at least one driver, selected from a gas turbine, steam turbine and electrical motor. One suitable gas turbine is the aero-derivative gas turbine. Aero- derivative gas turbines have been derived from jet engines as used in airplanes. Suitably these are steam-injected gas turbines in which steam is injected into the combustor and gas path to increase the power output and the efficiency. Aero-derivative gas turbines are usually smaller than heavy duty gas turbines that are commonly used in LNG plants. However, they are more energy efficient, have good mechanical drive capabilities, have good efficiencies and can be exchanged quickly reducing maintenance outages. Aero-derivative gas turbines are typically not used due to its relative small size compared to heavy duty gas turbines. However, in the present invention these aero-derivative gas turbines can be excellently used, since the use of a plurality of compressors makes it possible to employ smaller turbines, such as aero-derivative gas turbines.

It is possible to apply one driver that is coupled to more than one refrigerant compressor. This may have a beneficial effect on the capital expenses. However, the flexibility of the operation is enhanced if each compressor in the compressor unit is coupled with a separate driver, allowing the optimisation of excess capacity for each refrigerant duty. The skilled person has the option to optimise the capital costs on the one hand, which would benefit fewer turbines, and the flexibility and availability on the other hand, which would promote more drivers, such as one driver per compressor. It would also be possible to use one driver for more than one compressor, whereby the compressors would provide refrigerant to different heat exchangers. In this way the advantages of flexibility and reduced number of drivers would be combined.

The capacity of the compressors in the compressor unit is suitably selected to provide an excess capacity of refrigerant with regard to the maximum inlet flow of the heat exchanger. The capacities of the compressors in each compressor unit may vary. However, in order to facilitate the operation when one compressor has to be taken out, the capacity of each compressor in the compressor unit has substantially the same capacity. By substantially the same capacity is understood that the compressors have capacities that differ 5% or less from each other.

As indicated above, the refrigerants may be selected from a variety of compounds, known in the art. Suitable refrigerants include nitrogen, methane, ethane, ethylene, propane, propylene, one or more butane isomers, one or more pentane isomers and mixtures thereof. The refrigerants may be used in a number of refrigerants streams. Hence, it is possible to employ one refrigerant stream, but also more streams are possible, e.g., two to four refrigerant streams. The refrigerant compounds used in the various refrigerant streams may be the same or different. The use of different refrigerant compounds is preferred since that allows easy application of different temperature regimes when more than one heat exchanger is used.

The skilled person will understand that when the refrigerant is compressed in the compressor unit, the temperature of the compressed refrigerant will go up. Suitably, the compressed refrigerant is cooled before being expanded. The cooling may be accomplished in any way known in the art. Typically air or water coolers are employed. However, it is also possible to use other streams that are available in the LNG process for cooling purposes. By using other process streams of the LNG process the thermal efficiency of the process may be optimised.

The skilled person may employ any expansion method that he would like to use. Typically some expansion takes place in the heat exchanger. In this way liquid refrigerant evaporates and absorbs heat from the hydrocarbon stream. However, it is advantageous to employ an expansion means that allows adiabatic expansion of the compressed refrigerant so that the temperature of the refrigerant is lowered before it enters the heat exchanger. Suitable expansion means include pressure reduction valves, such as a Joule-Thomson valve, and/or a hydraulic expander and/or expansion engines such as turbines and/or an expansion vessel or a combination of these expansion means in series and/or parallel configuration. Therefore the compressed refrigerant is advantageously expanded via an expansion means, wherein a Joule-Thomson valve is preferred.

It is possible to employ the method of the present invention for cooling any

hydrocarbon stream. For that purpose one may pass the hydrocarbon stream suitably through one to four heat exchangers that operate in series and/or in parallel. With heat exchangers that operate in parallel the size of the equipment used, such as heat exchangers and/or compressors may be designed in an optimal way. When a parallel operation of heat exchangers is desired, the number of parallel heat exchangers typically varies between two and four. With heat exchangers in series, the product is successively cooled so that a sufficiently cooled hydrocarbon is produced that may be used for various objectives. When the hydrocarbon streams contains heavier products, such as hydrocarbons with 2 or more carbon atoms, such as ethane, ethylene, propane, butanes and pentanes, these heavier hydrocarbons may be easily recovered, in particular separately from each other. However, it is preferred to use the method in the preparation of liquefied natural gas. Therefore, the cold hydrocarbons stream preferably contains methane and the stream is cooled to liquefaction, yielding liquefied natural gas. The liquefaction may be obtained in one to four heat exchangers that operate in series. When more than one heat exchanger is used, it is not required that all that exchangers operate in accordance with the method of the present invention. It is possible to run a number of heat exchangers in accordance with known operations and techniques. However, the method according to the present invention is preferably applied in all heat exchangers when more than one heat exchanger is used. The methane-containing hydrocarbon stream is advantageously pre-treated to remove noxious contaminants from the hydrocarbon stream. Noxious components that are suitably removed before the hydrocarbons stream is subjected to liquefaction include carbon monoxide, carbon dioxide, hydrogen sulphide, thiols, ammonia, but also hydrocarbons with two or more carbon atoms per molecule.

The present invention is particularly useful for producing liquefied natural gas (LNG). In such cases the hydrocarbon stream suitably comprises at least 60%vol methane. More preferably, the methane content in the hydrocarbon stream is at least 70 %vol, even more preferably at least 80%vol. The remaining portion of the hydrocarbon stream may contain nitrogen, and the other compounds mentioned above, viz. carbon monoxide, carbon dioxide, hydrogen sulphide, thiols, ammonia, but also hydrocarbons with two or more carbon atoms per molecule. It is understood that some natural gas sources may contain very high concentrations of carbon dioxide and/or ammonia and/or hydrogen sulphide. Such

concentrations may amount to 60%vol or higher. The skilled person will realise that such streams will be treated first in order to remove these components, e.g., by amine treatment. The product thus obtained, containing at least 60 %vol methane, may be subjected to the process according to the present invention.

The conditions for producing LNG are well known. Such conditions may be applied in the process according to the present invention. Suitable conditions for the compressor units include a compression of the refrigerants to a pressure ranging from 10 to 65 bar, preferably 20 to 55 bar, more preferably from 25 to 50 bar, most preferably from 25 to 45 bar. In the expansion stage the compressed refrigerant may be expanded to a pressure ranging from 8 to 0.1 bar, suitably to a pressure ranging from 0.5 to 5 bar. The skilled person may select the optimal conditions based on i.a. the number of heat exchangers and the desired levels of cooling for the hydrocarbon stream. In a typical case the hydrocarbon stream is cooled in stages wherein the temperature may be brought down in two to four stages from about ambient temperature, e.g., 20 °C, to -165 °C. At a temperature of 70 to 0 °C the hydrocarbon stream is suitably treated to remove contaminants. In a further stage the stream may be cooled to a temperature of - 30 to -80 °C. In one or more further heat exchangers, the temperature is then reduced to below the liquefaction temperature for methane, yielding LNG.

The invention also provides an apparatus for cooling a hydrocarbon stream

comprising

- a heat exchanger provided with a first side for refrigerant having a first side inlet and a first side outlet, and a second side for the hydrocarbon stream to be cooled, which second side is provided with a second side inlet and a second side outlet;

- a compressor unit for compressing the refrigerant comprising at least two compressors, the first side outlet of the heat exchanger being connected with an inlet of each of the

compressors of the compressor unit, and the first site inlet being connected to an outlet of each of the compressors in the compressor unit; and

- an expansion means that is provided in fluid communication with the outlets of each of the compressors and the first site inlet of the heat exchanger, wherein the heat exchanger has a maximum inlet flow for refrigerant for the first site inlet and the compressor unit, when in operation, has a design capacity in excess of that maximum inlet flow of the heat exchanger.

The expansion means that is contained in the apparatus according to the present invention is preferably a Joule-Thomson valve or a combination as described above.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention will be further illustrated by means of the figures.

Figure 1 shows an embodiment of the present invention wherein LNG is produced in two refrigeration cycles. A refrigeration cycle is shown as a closed loop in the liquefaction process wherein a refrigerant is compressed and expanded and withdraws heat in the heat exchanger and disposes of heat in a cooler system.

Figure 2 shows another embodiment wherein LNG is produced in two parallel series of heat exchangers, and wherein drivers are coupled with multiple compressors, each compressor being tied to its closed refrigerant cycle.

It is evident that the figures represent simplified schemes only. Auxiliary equipment has not been shown as will be clear to the skilled person. It is understood by those skilled in the art that parts and concepts from this invention can be incorporated in one or multiple single refrigerant cycles as part of a single or multiple refrigerant LNG liquefaction process. The preferred forms of the invention described below are to be used as illustration only, and should not be used in a limiting sense to interpret the scope of the present invention. Obvious modifications to the exemplary embodiments, set forth above, could be readily made by those skilled in the art without departing from the spirit of the present invention.

The figures will be further explained, whilst referring to the production of LNG. It is emphasised that the invention may also be used for other purposes, such as the cooling of hydrocarbon streams to obtain liquid hydrocarbons with 2 or more carbon atoms per molecule. In Figure 1 two heat exchangers 1 and 2 are shown. Natural gas, from which contaminants such as ammonia, hydrogen sulphide and carbon dioxide have been removed, is fed via a line 3 into heat exchanger 1. Into heat exchanger 1 are also fed a first refrigerant, such as nitrogen, propane, mixed refrigerant or methane gas, via a line 30 and a second refrigerant, e.g., mixed refrigerant or nitrogen, via a line 10. The second refrigerant in line 10 is precooled in heat exchanger 1 , together with the natural gas in line 3. The first refrigerant is passed through the heat exchanger 1 and leaves the heat exchanger via a line 31 . Via an expansion means 46 where the first refrigerant expands and cools off, and a line 47 the first refrigerant is passed to the heat exchanger 1. The first refrigerant is subsequently further evaporated in heat exchanger 1 by absorbing heat from the streams in lines 3 and 10. The heat that is absorbed by the adiabatic evaporation cools the natural gas in line 3 and the second refrigerant in line 10. The line 3 forms the second side and the environment in heat exchanger 1 around the line 3 forms the first side of the heat exchanger. Although line 3 has been shown here as a single conduit, it is clear to the skilled person that the heat exchange surfaces may be made very large, e.g. via a bundle of conduits, to facilitate the heat exchange process. The first refrigerant is withdrawn from heat exchanger 1 via a line 32. From line 32 the refrigerant is split into three and is fed via lines 33, 34 and 35 to

compressors 36, 38 and 40, respectively. Although in the figure three compressors are shown, it is clear that less or more compressors, e.g., two, four or five, may also be used. These compressors are operating in parallel and have a combined capacity above the maximum capacity of the heat exchanger as expressed in the maximum refrigerant flow that can be fed via line 30. The compressors have been coupled with drivers, in this case gas turbines, 37, 39 and 41 , respectively. In the Figure the compressors have been schematically indicated. It will be evident to the skilled person that each compressor may be selected from a variety of equipment, including a plurality of compression apparatuses that in combination provide the desired compression duties. The compressors 36, 38 and 40 together with the drivers 37, 39 and 41 , constitute the compressor unit.

Compressed first refrigerant leaves the respective compressors via lines 42, 43 and 44, and is combined into line 30. The compressed refrigerant may have an elevated temperature. Therefore, it is suitably cooled in an air or water cooler, indicated by 45 before it is recycled into the heat exchanger 1.

Cooled natural gas leaves heat exchanger 1 via a line 4 and is passed into the second heat exchanger 2. The cooled second refrigerant leaves the heat exchanger 1 via a line 1 1 and is also passed into the heat exchanger 2. The refrigerant leaves the heat exchanger 2 and is passed via a line 12 and an expansion means 13 and a line 14 back into the heat exchanger 2. In the expansion means the compressed refrigerant is at least partly

adiabatically evaporated so that cold is created. The cold created by the evaporation is used to cool the natural gas in line 4 further to at least partial liquefaction. The at least partially liquefied natural gas leaves the heat exchanger 2 via a line 5. It may be further expanded in an expansion means 6 and the expanded product is withdrawn via line 7. The products may be split into a fuel product, withdrawn via a line 8, and LNG, withdrawn via a line 9. The fuel product may comprise methane and nitrogen and/or heavier hydrocarbons.

The second refrigerant that has been at least partly evaporated is withdrawn from the heat exchanger 2 via a line 15. Thereafter it is split into three. Via lines 16, 20 and 19 the refrigerant is passed to compressors 17, 21 and 23, respectively. The compressors are driven via gas turbines 18, 22 and 24, respectively. Although in the figure three compressors, lines and turbines are shown, it is clear that also two or more compressors, lines and turbines, e.g., four or five, may also be used.

Compressed second refrigerant leaves the respective compressors via lines 25, 26 and 27, and is combined into line 10. The compressed refrigerant may have an elevated temperature. Therefore, it is cooled in an air or water cooler, indicated by 28, before it is recycled into the heat exchanger 1. When one compressor, e.g. compressor 36, is switched off for repair or for any other reason, the other compressors, e.g., compressors 38 and 40, have additional capacity to compensate, at least partly, for the switching off of compressor 36.

Figure 2 shows an alternative embodiment where each refrigeration cycle is conducted in two parallel heat exchangers. Natural gas is fed via line 103, split into two, and via lines 103a and 103b fed into heat exchanger 101 a and 101 b, respectively. Into heat exchangers 101 a and 101 b are also fed a first refrigerant via a line 130a and 130b, and a second refrigerant via a line 1 10a and 1 10b. The second refrigerant in lines 1 10a and 1 10b is precooled in heat exchangers 101 a and 101 b, together with the natural gas in lines 103a and 103b. The first refrigerant is passed through the heat exchangers 101 a and 101 b and leaves the heat exchangers via lines 131 a and 131 b. It is passed through expansion means 161 a and 161 b, and is recycled to the heat exchangers 101 a and 101 b through lines 160a and 160b, respectively. The refrigerant is subsequently evaporated into heat exchanger 101 a and 101 b. The cold that is created by the adiabatic evaporation cools the natural gas in lines 103a and 103b and the second refrigerant in lines 1 10a and 1 10b. The lines 103a and 103b form the second side and the environment in heat exchangers 101 a and 101 b around the lines 103a and 103b form the first side in the heat exchangers. The first refrigerant is withdrawn from heat exchangers 101 a and 101 b via lines 132a and 132b, and combined into line 132. From the line 132 the refrigerant is split into three and is fed via lines 133, 134 and 135 to compressors 136, 137 and 138, respectively. Although in the figure three compressors, lines and turbines are shown, it is clear that two but also more compressors, lines and turbines, e.g., four or five, may also be used.

These compressors are operating in parallel and have a combined capacity above the maximum capacity of the heat exchanger as expressed in the maximum refrigerant flow that can be fed via lines 130a and 130b.

Compressed first refrigerant leaves the respective compressors via lines 142, 143 and 144, and is combined into line 130. The compressed refrigerant may have an elevated temperature. Therefore, it is suitably cooled in an air or water cooler, indicated by 145 before it is recycled into the heat exchanger 1 . The cooler may be positioned before the line 130 is split. Alternatively, two smaller coolers may be positioned such that the refrigerants in lines 130a and 130b are cooled separately.

Cooled natural gas leaves heat exchangers 101 a and 101 b via lines 104a and 104b and is passed into second heat exchangers 102a and 102b. The cooled second refrigerant leaves the heat exchangers 101 a and 101 b via line 1 1 1 a and 1 1 1 b and is also passed into the heat exchangers 102a and 102b. The refrigerant streams leave the heat exchanger 102a and 102b and are passed via lines 1 12a and 1 12b to expansion means 1 13a and 1 13b. From the expansion means 1 13a and 1 13b the refrigerant is returned to the heat exchangers 102a and 102b via lines 1 14a and 1 14b. In the expansion means 1 13a and 1 13b the compressed refrigerant is at least partly adiabatically expanded and optionally at least partly evaporated so that cold is created. The cold created by the evaporation is used to cool the refrigerant lines 1 1 1 a and 1 1 1 b and the natural gas in lines 104a and 104b further to at least partial liquefaction. The at least partially liquefied natural gas leaves the heat exchangers 102a and 102b via lines 105a and 105b. The at least partly liquefied natural gas is combined into a line 105. It may be further expanded in an expansion means 106 and the expanded product is withdrawn via line 107. The products may be split into a fuel product, as indicated above, that is withdrawn via a line 108, and LNG, withdrawn via a line 109.

The second refrigerant that has been at least partly evaporated is withdrawn from the heat exchangers 102a and 102b via lines 1 15a and 1 15b. The two streams are combined into a line 1 15. Thereafter it is split into three. Via lines 1 16, 120 and 1 19 the refrigerant is passed to compressors 1 17, 121 and 123, respectively. The compressors are driven via gas turbines 150, 151 and 152, respectively. Although in the figure three compressors, lines and turbines are shown, it is clear that two but also more compressors, lines and turbines, e.g., four or five, may also be used.

Compressed second refrigerant leaves the respective compressors via lines 125, 126 and 127, and is combined into line 1 10. The compressed refrigerant may have an elevated temperature. Therefore, it is suitably cooled, e.g., in an air or water cooler, indicated by 128, before it is recycled into the heat exchanger 101 a and 101 b.

The compressors 136, 1 17, 137, 121 , 138 and 123 are coupled with three drivers.

Compressors 136 and 1 17 are coupled with a gas turbine 150; compressors 137 and 121 are coupled with a gas turbine 151 and compressors 138 and 123 are coupled with a gas turbine 152. In this way the capital expense for a plurality of gas turbine drivers may be avoided. However, when one of the compressors is to be taken out, there are two remaining compressor pairs that can provide sufficient capacity to keep the LNG plant on line.

Although in the Figures 1 and 2 two refrigerant lines are shown, it is clear that another number, e.g., one, three or four, refrigerant lines may also be used. The Figure 2 also shows two parallel heat exchanger streams; however it is evident that another number, e.g., one or three, parallel heat exchangers may also be used.