PRODUCTION OF HYDROCARBONS

THIS INVENTION relates to the production of hydrocarbons. In particular, the invention relates to a process for producing hydrocarbons from natural gas.

According to the invention, there is provided a process for producing hydrocarbons from natural gas, the process including in a reforming stage, reforming natural gas to form synthesis gas; in a hydrocarbon synthesis stage, converting at least a portion of the synthesis gas to hydrocarbons and producing a tail gas stream which includes one or more light hydrocarbons; cooling natural gas thereby to form a natural gas liquid phase and an uncondensed natural gas gaseous phase; separating the natural gas liquid phase and the natural gas gaseous phase; and in a cold separation stage, cold separating at least one light hydrocarbon stream enriched in light hydrocarbons from the tail gas stream producing a lean tail gas stream, using the natural gas liquid phase in indirect heat exchange fashion as a cold utility.

In this specification, the term "light hydrocarbons" is intended to refer to hydrocarbons that are gaseous at atmospheric conditions, e.g. Ci to C ₄ hydrocarbons.

The cold separation stage may include one or more distillation operations operating with minimum temperatures below -45O, or even below -100 ⁹ C, e.g. around -

Typically, the process includes recycling at least a portion of the lean tail gas stream for hydrocarbon synthesis purposes. The lean tail gas may thus be recycled to the hydrocarbon synthesis stage. Alternatively, or in addition, the process may include recycling at least a portion of the lean tail gas stream to the reforming stage.

The process typically includes pumping the natural gas liquid phase to an elevated pressure, and evaporating at least a portion, typically all, of the natural gas liquid phase as a result of its use as a cold utility, i.e. as a cooling fluid. The natural gas liquid phase is preferably pumped to a pressure higher than the operating pressure of the reforming stage. As will be appreciated, the evaporated cold utility can then be fed to the reforming stage for reforming to synthesis gas, without further work being performed on the evaporated cold utility. Advantageously, this evaporated cold utility is leaner in inert and other incondensable or light components, than natural gas not passed through said expansion and separation steps.

The process may include using the natural gas gaseous phase as a fuel gas. Advantageously, this acts as a purge to remove inerts such as nitrogen and other uncondensed components from the process, or more accurately, prevents or reduces the feeding of such inerts and uncondensed components to the hydrocarbon synthesis stage of the process of the invention. A portion of the lean tail gas stream may be used with the natural gas gaseous phase as fuel gas, and advantageously serves to purge the hydrocarbon synthesis stage of inerts that may build up due to the recycle of the lean tail gas stream.

If desired or necessary, the process may include removing CO ₂ from the tail gas stream prior to subjecting the tail gas stream to cold separation in the cold separation stage. Any suitable conventional CO ₂ removal technology may be employed, e.g. a CO ₂ absorption process employing an amine wash or a methanol wash (e.g. Rectisol).

Instead, or in addition, the process may include separating CO ₂ from the tail gas stream in the cold separation stage and producing a recovered CO ₂ stream. This may for example be achieved by employing a suitably adapted Ryan/Holmes separation configuration as disclosed in e.g. US 4,318,723 and/or US 4,462,814. In such configurations a solids-preventing agent is employed to prevent CO ₂ from freezing. Examples of solids-preventing agents given comprises ethane, propane, butane, pentane or mixtures thereof, thus advantageously including light hydrocarbons already present in the tail gas stream.

Separating CO ₂ from the tail gas stream in the cold separation stage may include recycling a portion of the recovered CO ₂ stream to or within the cold separation stage. This serves to increase the CO ₂ partial pressure and so inhibit the CO ₂ from freezing. Thus, in one such embodiment, separating CO ₂ from the tail gas stream in the cold separation stage includes separating the tail gas stream in a first distillation operation to produce a first bottoms stream enriched in C ₂₊ hydrocarbons and a first overheads stream enriched in methane and components lighter than C ₂₊ hydrocarbons, feeding the first bottoms stream to a second distillation operation to produce a second overheads stream enriched in CO ₂ , which is the recovered CO ₂ stream, and a second bottoms stream further enriched in C ₂₊ hydrocarbons, and recycling a portion of the

recovered CO ₂ stream to the first distillation operation. The portion of the recovered CO ₂ stream stream may be recycled to a condenser of the first distillation operation. The process may further include recycling a portion of the second bottoms product to the first distillation operation. This recycle inter alia serves to increase temperatures in the first distillation operation and so aids to inhibit CO ₂ freezing.

The process may further include, in the cold separation stage, removing the recovered CO ₂ stream or a portion thereof in liquid form from the tail gas stream. Advantageously, liquefied CO ₂ is pumpable, facilitating sequestering thereof.

Regardless of how CO ₂ is removed from the tail gas stream, the process may include using at least a portion of the removed CO ₂ in the reforming stage to adjust the H ₂ :CO ratio of the synthesis gas produced by the reforming of the natural gas. Again, having the CO ₂ in a pumpable form is advantageous.

Typically, the natural gas reformed and the natural gas cooled are from a common natural gas feed stream which is at elevated pressure. Cooling the natural gas may include expanding the natural gas, e.g. a portion of the natural gas feed stream. Typically, the natural gas or natural gas feed stream is at a pressure of at least 40 bar(g), and is expanded to a pressure of less than 10 bar(g), more typically 2 to 4 bar(g). If necessary or desirable, the cooling may include further steps in addition to the expansion of the natural gas. Such additional steps may for example include compressing and/or cooling the natural gas feed stream or/at least a portion thereof. Conventional technologies using refrigeration methods employed in the production of

liquefied natural gas (LNG) may be employed, e.g. cascade refrigeration processes or mixed-refrigerant processes.

If necessary or desirable, the process may include removing CO ₂ from the natural gas or natural gas feed stream, or at least a portion thereof, prior to cooling the natural gas, to prevent CO ₂ from freezing and blocking process equipment.

Conventional technologies for the removal of CO ₂ from natural gas may be employed, e.g. an amine wash.

The hydrocarbon synthesis stage may be a conventional hydrocarbon synthesis stage. Typically, the hydrocarbon synthesis stage includes Fischer-Tropsch synthesis using one or more Fischer-Tropsch hydrocarbon synthesis stages. Typically, the tail gas stream from the hydrocarbon synthesis stage includes light hydrocarbons, CO ₂ , CO and H ₂ .

The one or more Fischer-Tropsch hydrocarbon synthesis stages may be provided with any suitable reactors such as one or more reactors selected from fixed bed reactors, slurry bed reactors, ebullating bed reactors or dry powder fluidised bed reactors. The pressure in the reactors may be between 1 bar(g) and 100 bar(g), while the temperature may be between 16OO and 380O.

One or more of the Fischer-Tropsch hydrocarbon synthesis stages may be a low temperature Fischer-Tropsch hydrocarbon synthesis stage operating at a temperature of less than 280O. Typically, in such a low temperature Fischer-Tropsch hydrocarbon synthesis stage, the hydrocarbon synthesis stage operates at a

temperature of between 160O and 280O, preferably between 220O and 260O, e.g. about 230 ⁹ C. Such a low temperature Fischer-Tropsch hydrocarbon synthesis stage is thus a high chain growth, typically slurry bed, reaction stage, operating at a predetermined operating pressure in the range of 10 to 50 bar(g).

One or more of the Fischer-Tropsch hydrocarbon synthesis stages may be a high temperature Fischer-Tropsch hydrocarbon synthesis stage operating at a temperature of at least 320 ⁹ C. Typically, such a high temperature Fischer-Tropsch hydrocarbon synthesis stage operates at a temperature of between 320O and 380O, e.g. about 350O, and at an operating pressure in the range of 10 to 50 bar(g). Such a high temperature Fischer-Tropsch hydrocarbon synthesis stage is a low chain growth reaction stage, which typically employs a two-phase fluidised bed reactor. In contrast to the low temperature Fischer-Tropsch hydrocarbon synthesis stage, which may be characterised by its ability to maintain a continuous liquid product phase in a slurry bed reactor, the high temperature Fischer-Tropsch hydrocarbon synthesis stage cannot produce a continuous liquid product phase in a fluidised bed reactor.

It will be appreciated that the natural gas liquid phase may not be a sufficiently large cold utility to satisfy the entire cooling duty of the cold separation stage, and that it may thus be necessary to employ an additional cold utility, e.g. a propane refrigeration cycle, in the cold separation stage to satisfy the cooling duty of the cold separation stage.

The invention will now be described, by way of example, with reference to the accompanying drawings, in which:

Figure 1 shows a process in accordance with the invention for producing heavy and light hydrocarbon products from natural gas, the process including a cold separation stage; and

Figure 2 shows an embodiment of the cold separation stage of Figure 1 in greater detail.

Referring to Figure 1 of the drawings, reference numeral 10 generally indicates a process in accordance with the invention for producing hydrocarbon products from natural gas. The process 10 includes a natural gas cooling and liquefaction stage 12, a gas/liquid separator 14, a reforming stage 16, a hydrocarbon synthesis stage 18, a cold separation stage 20 and a product work-up stage 22. A natural gas feed line 24 splits before the natural gas cooling and liquefaction stage 12 so that it leads to both the natural gas cooling and liquefaction stage 12 and to the reforming stage 16. A gas/liquid line 26 connects the natural gas cooling and liquefaction stage 12 to the gas/liquid separator 14. A fuel gas line 28 and a liquefied natural gas line 30 lead from the gas/liquid separator 14. The liquefied natural gas line 30 leads via a high pressure pump 31 to the cold separation stage 20.

A synthesis gas line 32 leads from the reforming stage 16 to the hydrocarbon synthesis stage 18. A hydrocarbon line 34 leads from the hydrocarbon synthesis stage

18 to the product work-up stage 22, and a tail gas line 36 leads from the hydrocarbon synthesis stage 18 to the cold separation stage 20. A hydrocarbon product line 38 leads from the product work-up stage 22. A light hydrocarbon line 44 leads from the cold separation stage 20 to the product work-up stage 22, and a recovered CO ₂ line 40 leads from the cold separation stage 20.

The cold separation stage 20 is also connected to the hydrocarbon synthesis stage 18 by a lean tail gas line 42. An evaporated natural gas line 46 leads from the cold separation stage 20 to the reforming stage 16. A fuel gas line 48 from the cold separation stage 20 joins the fuel gas line 28.

In the process 10, natural gas, typically at a pressure of more than 40 bar(g), is received by means of the natural gas feed line 24. A portion of the natural gas is fed to the natural gas cooling and liquefaction stage 12 with the remainder of the natural gas being fed to the reforming stage 16.

In the reforming stage 16, the natural gas is reformed in conventional fashion in the presence of steam, producing a synthesis gas which includes at least H ₂ and CO. Typically, the synthesis gas also includes unreformed methane and CO ₂ .

The synthesis gas is converted in the hydrocarbon synthesis stage 18 to hydrocarbons. The hydrocarbon synthesis stage 18 is a Fischer-Tropsch synthesis stage and may include one or more low temperature Fischer-Tropsch hydrocarbon synthesis stages, and/or one or more high temperature Fischer-Tropsch hydrocarbon synthesis stages. Fischer-Tropsch synthesis of hydrocarbons using synthesis gas is a well-known process and will not be described in any more detail.

A tail gas stream which includes light hydrocarbons and unreacted synthesis gas is removed from the hydrocarbon synthesis stage 18 by means of the tail gas line 36. The balance of the hydrocarbons are removed from the hydrocarbon synthesis

stage 18 by means of the hydrocarbon line 34 and routed to the product work-up stage 22. It must be understood that, although not shown in Figure 1 , the process 10 will also include process steps for the treatment of reaction water produced in the hydrocarbon synthesis stage 18. Such steps are standard and are not discussed in further detail.

The portion of the natural gas fed to the natural gas cooling and liquefaction stage 12 is subjected to cooling causing a portion of the natural gas to liquefy, typically at temperatures around -150O. The cooling of the natural gas includes expanding said portion of natural gas to a pressure of less than 10 bar(g), typically in the range of from 2 to 4 bar(g). Cooling of the natural gas to liquefy a portion of the natural gas typically includes further steps in addition to the expansion of said portion of said natural gas feed stream. Such further steps may for example include compressing and/or cooling the natural gas feed stream or/at least a portion thereof. Such cooling may for example be achieved using refrigeration methods commonly employed in the production of liquefied natural gas (LNG), for example cascade refrigeration processes or mixed- refrigerant processes. A gas/liquid mixture is thus produced which is removed by means of the gas/liquid line 26 and separated in the gas/liquid separator 14. An uncondensed gaseous phase is removed by means of the fuel gas line 28 and can be used as a fuel gas at about 4 bar(g) for heating and/or other purposes.

Liquefied natural gas is withdrawn from the gas/liquid separator 14 by means of the liquefied natural gas line 30 and is pumped to a pressure of about 35 bar(g) by the pump 31 before being fed to the cold separation stage 20 as a cold utility, i.e. as a cooling fluid.

In the cold separation stage 20, the cold utility thus provides at least a portion of the indirect cooling duty required to separate and recover light hydrocarbons from the tail gas stream being fed to the cold separation stage 20 by means of the tail gas line 36. An embodiment of the cold separation stage 20 is shown in greater detail in Figure 2 of the drawings. The cold separation stage 20 includes a first distillation operation (comprising inter alia a first distillation column 100 and an overhead condenser system 104, and also a reboiler (not shown)), and a second distillation operation 102 (comprising inter alia an overhead condenser and associated reflux system (not shown) and a reboiler (not shown). The tail gas line 36 feeds into the column 100. A first bottoms product line 106 from the first distillation operation connects the column 100 to the second distillation operation 102, while an overhead vapour line 108 connects the column 100 to the overhead condenser system 104. A gaseous top product line 1 12 connects the second distillation operation 102 to the overhead condenser system 104, with the recovered CO ₂ line 40 branching from the top product line 1 12. A second bottoms product line 1 14 leads from the second distillation operation 102 to the overhead condensing system 104, with the light hydrocarbon line 44 branching from the second bottoms product line 1 14. A reflux line 1 10 connects the overhead condenser system 104 to the column 100. The lean tail gas line 42 leads from the overhead condenser system 104, with the fuel gas line 48 branching from the lean tail gas line 42.

Tail gas fed to the cold separation stage 20 is routed along the tail gas line 36 and fed to the column 100, in which it is separated into a first bottom product enriched in C ₂₊ hydrocarbons and which includes CO ₂ that is withdrawn along the first bottoms product line 106 and an overhead vapour enriched in Ci and lighter components withdrawn along the overhead vapour line 108. Although not shown in

Figure 2, the tail gas may be compressed and/or cooled prior to feeding it to the column 100. The first bottom product is routed to the second distillation operation 102 in which it is separated into a second bottoms product further enriched in C ₂₊ hydrocarbons withdrawn along the second bottoms product line 1 14 and a gaseous top product enriched in CO ₂ withdrawn along the gaseous top product line 1 12. Portions of the second bottoms product and the gaseous top product are routed along the line 1 14 and the line 1 12 respectively and fed to the overhead condensing system 104, with the balance being withdrawn along the light hydrocarbon product line 44 and the recovered CO ₂ line 40 respectively. Although not shown in the drawing, the cold separation stage 20 may further include steps to liquefy the recovered CO ₂ withdrawn along the line 40. Such steps may for example include cooling the recovered CO ₂ , possibly using the liquefied natural gas as cooling utility. Advantageously, as liquid CO ₂ is pumpable, it may be sequestered or routed as a feedstock (not shown) to the reforming stage 16 to adjust the H ₂ :CO ratio of the synthesis gas produced in the reforming stage 16 to ensure that the synthesis gas H ₂ :CO ratio is optimal for the Fischer-Tropsch hydrocarbon synthesis in the hydrocarbon synthesis stage 18.

In the overhead condensing system 104, the overhead vapour from the first distillation column 100 is cooled and partially liquefied together with the gaseous top product and the second bottoms product from the second distillation operation 102. The liquefied portion is withdrawn along the reflux line 1 10 and serves as reflux for the first distillation column 100, while the non-liquefied portion is withdrawn along the lean tail gas line 42. In this manner, the tail gas fed to the cold separation stage 20 along the tail gas line 36 is thus separated into:

a) lean tail gas withdrawn along the lean tail gas line 42, comprising Ci, unconverted synthesis gas and light inert components such as nitrogen; b) fuel gas, of the same composition as the lean tail gas, withdrawn along the fuel gas line 48; c) recovered CO ₂ , typically having a CO ₂ content above 90 molar %, withdrawn along the recovered CO ₂ line 40; and d) light hydrocarbons withdrawn along the light hydrocarbon line 44, comprising C ₂₊ hydrocarbons.

The operating conditions of especially the first distillation operation 100 must be carefully selected to avoid conditions in which CO ₂ freezes out. In the cold separation stage 20 conditions of CO ₂ freeze out are avoided by inter alia imposing a lower limit on the minimum temperature in the first distillation operation 100 and by the recycle of the gaseous top product enriched in CO ₂ from the second distillation operation 102 to the overhead system 104, thereby to increase the CO ₂ partial pressure. In addition, recycle of the gaseous top product enriched in CO ₂ and the second bottoms product from the second distillation operation 102 to the overhead system 104 also serves to increase the temperatures in the first distillation operation 100. In a computer simulation of the cold separation stage 20, the column 100 was simulated as having a minimum temperature of -45O, while the overhead system 104 was simulated as having a minimum temperature of -56 ⁹ C. The first distillation operation thus has a minimum operating temperature below -45 ⁹ C.

Although only partially shown in Figure 2, it must be understood that the liquefied natural gas cold utility is evaporated by indirect heat exchange, so at least

partially providing the cooling duty required for the overhead condenser system 104 and/or a condenser of the second distillation operation 102, and optionally cooling the recovered CO ₂ to liquefy the CO ₂ . An evaporated portion of the natural gas may be used in an upstream heat exchanger (not shown) to pre-cool tail gas in the tail gas line 36 before the tail gas is fed to the cold separation stage 20, and to preheat the natural gas. The evaporated heated natural gas is then fed to the reforming stage 16 by means of the natural gas line 46 which joins the natural gas feed line 24 upstream of the reforming stage 16. The natural gas reformed in the reforming stage 16 thus includes the evaporated heated natural gas.

Typically, a portion of the lean tail gas stream is recycled by means of the lean tail gas line 42 to the hydrocarbon synthesis stage 18, and a portion of the lean tail gas stream is purged as a fuel gas by means of the fuel gas line 48. In addition, and although not shown in the drawing, a portion of the lean tail gas stream may be recycled to the reforming stage 16.

The light hydrocarbons separated and recovered from the tail gas stream are removed from the cold separation stage 20. The light hydrocarbon line 44 represents the removal of the light hydrocarbons and routing thereof to the product work-up stage 22 and may comprise more than one physical stream.

In the product work-up stage 22, the hydrocarbons (including the light hydrocarbons recovered from the tail gas stream) are worked up and/or combined to produce a slate of hydrocarbon products, which are removed from the product work-up stage 22. The hydrocarbon product line 38 represents the removal of hydrocarbon

products from the product work-up stage 22 and may comprise more than one physical stream. Typically, a hydrogen feed stream (not shown) supplies hydrogen to the product work-up stage 22.

If it is necessary to remove CO ₂ from the natural gas being fed to the natural gas cooling and liquefaction stage 12, conventional technology for removing CO ₂ from natural gas may be employed.

Advantageously, the process 10, as illustrated, employs the elevated pressure at which natural gas is available to provide a cold utility economically to recover light hydrocarbons produced in a hydrocarbon synthesis stage. It is also an advantage of the process 10, as illustrated, that a portion of the inerts and other incondensable components present in natural gas are purged from the natural gas before the natural gas is reformed. In at least one embodiment of the invention, as illustrated, a CO ₂ stream is produced which can be liquefied.