Gas treatment method and apparatus including an oxidative process for treating a sour gas mixture using gas from an air separation process

The present invention relates to a gas treatment method including an oxidative process for the desulphurisation of a sour gas mixture, the oxidative process utilising gas from an air separation process, and to corresponding apparatus according to the

precharacterising clauses of the independent claims.

Prior art

Methods and apparatus for treating sour gas mixtures based on the Claus process are known from the prior art. Reference is e.g. made to the article“Natural Gas” in

Ullmann’s Encyclopedia of Industrial Chemistry, on-line publication 15 July 2006, DOI: 10.1002/14356007. a17_073.pub2, especially chapter 2.4,“Removal of Carbon Dioxide and Sulphur Components.” As mentioned in more detail below, sour gas mixtures to be treated accordingly can be obtained from starting gas mixtures like natural gas or gas mixtures obtained in refinery processes.

US 4,684,514 A discloses a method of recovering sulphur from a hydrogen sulphide- containing gas stream which removes water concurrently with the condensation of sulphur and which can be operated at high pressure.

US 2013/0071308 A1 relates to a method and to a plant for recovering sulphur from a sour gas containing hydrogen sulphide and carbon dioxide. Carbon dioxide is compressed and at least a part thereof is injected into an oil well.

The Claus process originally only mixed hydrogen sulphide or a corresponding sour gas mixture with oxygen and passed the mixture across a pre-heated catalyst bed. It was later modified to include a free-flame oxidation upstream the catalyst bed in a so- called Claus furnace. Most of the sulphur recovery units (SRU) in use today operate on the basis of a correspondingly modified process. If, in the following, therefore, shorthand reference is made to a“Claus process” or to a corresponding apparatus, this is intended to refer to a free-flame modified Claus process as just described. So-called oxygen enrichment is a well-known economic and reliable method of debottlenecking existing Claus sulphur recovery units with minimal capital investment. Oxygen enrichment is, however, as described in detail below, not limited to retrofitting existing Claus sulphur recovery units but can likewise be advantageous in newly designed plants. The“term oxygen enrichment” shall, in the following, refer to any method wherein, in a Claus sulphur recovery unit or in a corresponding method, at least a part of the air introduced into the Claus furnace is substituted by oxygen or a by gas mixture which is, as compared to ambient air, enriched in oxygen or, more generally, has a higher oxygen content than ambient air.

Oxygen or oxygen enriched gas mixtures for Claus sulphur recovery units can be, in general, provided by cryogenic air separation methods and corresponding air separation units (ASU) as known from the prior art, see e.g. Haering, H.-W.,“Industrial Gases Processing,” Wiley-VCH, 2008, especially chapter 2.2.5,“Cryogenic

Rectification.” Cryogenic air separation units typically comprise a so-called warm section configured for compression, pre-cooling, drying and pre-purification of feed air, and a so-called cold section configured for heat exchange and rectification.

US 2004/211183 A1 discloses a method for driving at least a compression machine of an air distillation unit which supplies oxygen and/or nitrogen and/or argon to an industrial plant producing water vapour. In normal running conditions, the compression machine is driven at least partly by a steam turbine fed with said water vapour, which is input at an input port of the turbine. The turbine has two input ports which correspond to different intake pressures. During at least one operating phase of said plant, the turbine is partly supplied with water vapour from an auxiliary water vapour source and input at the turbine other input port.

While the present invention is, in the following, described with a focus on cryogenic air separation, it can likewise be used with advantage with non-cryogenic air separation methods and units, e.g. based on pressure swing adsorption (PSA), particularly with desorption pressure levels below atmospheric pressure (Vacuum PSA, VPSA). Usage of the present invention is particularly advantageous if such methods or units operate using ratable equipment driven or drivable by using steam, particularly a steam turbine. An air separation process is part of the method according to the present invention described hereinbelow and an air separation unit is part of a corresponding plant.

The present invention is also not limited to the Claus process but can equally be used in other gas treatment methods including an oxidative process for desulphurisation of a sour gas mixture, provided that in such methods also oxygen, e.g. pure oxygen or oxygen contained in a component mixture which is enriched in oxygen, is at least temporarily provided by an air separation unit.

An object of the present invention is to provide improved methods of this kind, particularly in view of reducing capital and operating expenses.

Disclosure of the invention

In view of the above, the present invention provides a gas treatment method including an oxidative process for the desulphurisation of a sour gas mixture, the oxidative process utilising gas from an air separation process, and to a corresponding apparatus including the features of the independent claims, respectively.

The sour gas mixture may, in the present invention, particularly be obtained from a gas mixture containing hydrogen sulphide and optionally carbon dioxide and other sour gases, especially in a chemical and/or physical absorption step using an absorption liquid, particularly in a so-called amine unit. Obtaining a sour gas mixture can also form part of the invention. The oxidative process which is, according to the present invention, used for the desulphurisation of the sour gas mixture, is particularly a Claus process or a variant thereof. Advantageous embodiments of the present invention are the subject of the dependent claims and of the description that follows.

Further background of the invention

Before specifically referring to the features and advantages of the present invention, some terms used herein will be defined and briefly explained. Furthermore, the operating principle of a Claus sulphur removal unit will be further explained. While, in the following, the present invention and its technical background is described with a focus on the Claus process, the present invention can equally be used in other desulphurisation methods including an oxidative process, as already mentioned hereinbefore.

The term“desulphurisation” as used herein shall refer to any process including conversion of a first sulphur compound comprising sulphur at a lower oxidation stage, which is contained in a sour gas mixture, to a second sulphur compound comprising sulphur at a higher oxidation stage in a first reaction step, and particularly further including forming elementary sulphur from the second sulphur compound in a second reaction step, the elementary sulphur particularly being obtained in liquid state. The first sulphur compound may be hydrogen sulphide and the second sulphur compound may be sulphur dioxide. The first reaction step may particularly include combusting the first sulphur compound and the second reaction step may particularly include using a suitable catalysis reaction as generally known for the Claus process.

In the language as used herein, a mixture of components, e.g. a gas mixture, may be rich or poor in one or more components, where the term“rich” may stand for a content of more than 75%, 80%, 85%, 90%, 95%, 99%, 99.5% or 99.9% and the term“poor” for a content of less than 25%, 20%, 15%, 10%, 5%, 1 %, 0.5% or 0.1 %, on a molar, weight or volume basis. In the field of sour gas treatment, a sour gas mixture with a hydrogen sulphide content of more than 80% is generally referred to as“rich” while a sour gas mixture containing less hydrogen sulphide is generally referred to as“lean.” A mixture may also be, in the language as used herein, enriched or depleted in one or more components, especially when compared to another mixture, where“enriched” may stand for at least 1 , 5 times, 2 times, 3 times, 5 times, 10 times or 100 times of the content in the other mixture and“depleted” for at most 0.75 times, 0.5 times, 0.25 times, 0.1 times, or 0.01 times of the content in the other mixture.

The term“sour gas mixture” refers, in the language as used herein, to a gas mixture containing at least hydrogen sulphide and optionally carbon dioxide and other known sour gases in an amount of at least 50%, 75%, 80% or 90% by volume, this numbers relating to the content of one of these compounds or to a common content of several ones. Further components besides sour gases may be present in a sour gas mixture as well, particularly water, hydrocarbons, benzene, toluene and xylenes (BTX), carbon monoxide, hydrogen, ammonia and mercaptans. The terms“pressure level” and“temperature level” are used herein in order to express that no exact pressures but pressure ranges must be used in order to realise the present invention and advantageous embodiments thereof. Different pressure and temperature levels may lie in distinctive ranges or in ranges overlapping each other. They also cover expected and unexpected, particularly unintentional, pressure or temperature changes, e.g. inevitable pressure or temperature losses. Values expressed for pressure levels in bar units are absolute pressure values.

In air separation methods and corresponding air separation units, particularly in cryogenic air separation methods and corresponding air separation units, the air to be treated is compressed, cleaned and cooled before it is subjected to separation, e.g. before it is fed into a distillation column system in a cryogenic method.

Compressors for use in air separation units, be it of the cryogenic or the non-cryogenic type, can be designed as turbo or positive displacement machines, the two types differing in their operational behaviour. With turbo machines, the amount of

compressed gas decreases with increasing pressure, while in positive displacement machines nearly a constant mass flow independently from the discharge pressure of the compressor can be achieved. Multiple-stage turbo compressors are by far the most frequently used machines in cryogenic air separation. Turbo compressors can be of the radial or the axial type. They differ from each other in the direction by which the compressed gas leaves the impeller. A radial turbo compressor is typically made up of several stages which are arranged on one or more shafts. These shafts are driven via a gear either by an electric motor or a steam turbine.

The compression of the air is at least in part an adiabatic process. The compression work carried out during compression thus increases the internal energy of the air so that its temperature rises. The latter is also referred to as compression heat. Air compressed in a main air compressor (MAC), e.g. of the turbo type, of an air separation unit is heated by the compression typically to about 100 °C and is therefore, in conventional processes as known from the prior art, prior to being cooled via a heat exchange with air separation products, pre-cooled with water.

If, in the following, the term“main air compressor” is used, this term is intended to refer to compressor(s) of a cryogenic or non-cryogenic air separation unit which compress(es) all the air to be separated to a certain pressure level. A main air compressor may be followed by a so-called booster air compressor (BAC) or several so-called boosters driven by turbines. The latter machines, however, are only used for parts of the air previously compressed by the main air compressor. Herein, a main air compressor and a booster air compressor are to be understood as machines entirely or at least partially driven by external energy, the term“external energy” referring to energy which was not obtained by expanding process streams formed in the air separation unit itself using e.g. turboexpanders.

In classical cryogenic air separation units as shown in Figure 2.3A in Haering, all the feed air into the rectification column system is compressed to a pressure at or slightly above the operating pressure of the high pressure column in the main air compressor, and only a part of the air such compressed is further compressed to a higher pressure in a so-called booster air compressor. Such classical configurations are often also referred to as“MAC/BAC” configurations. In contrast, in more recent so-called“high air pressure” (“HAP”) configurations, all the feed air is compressed in the main air compressor to a pressure significantly, i.e. at least 2, 3, 4, 5 or 10 bar, and up to 20 bar or more, above the operating pressure of the high pressure column. This does, however, not exclude that parts of the air such compressed are further compressed in booster air compressors or other further machines. High air pressure configurations are known from EP 2 466 236 A1 , EP 2 458 311 A1 and US 5,329,776 A.

A sour gas mixture used as a feed for a Claus sulphur recovery unit usually originates from a sour gas sweetening plant, e.g for sweetening natural gas or a gas from a petrochemical or oil refinery plant. The sour gas mixture, containing varying amounts of hydrogen sulphide and carbon dioxide, is saturated with water and frequently also contains small amounts of hydrocarbons and other impurities in addition to the principal components. The sour gas mixture enters a typical Claus sulphur recovery unit at about 0.5 to 1.0 barg or about 0.8 to 1.3 barg and 50 °C. In classical Claus sulphur recovery units, combustion air is compressed to an equivalent pressure by centrifugal blowers. Both inlet streams then flow to a burner which fires into the Claus furnace, the burner being fed with a further fuel.

The gas mixture from the Claus furnace, at a temperature of typically 900 °C and up to 1 ,450 °C, is typically cooled while generating high-pressure steam in a waste heat boiler and further cooled while producing low-pressure steam in a separate heat exchanger. This cools the hot gases to approximately 160 °C, condensing most of the sulphur which has already formed up to this point. The resultant liquid sulphur is removed in a separator section of the condenser and flows by gravity to a sulphur storage tank. Here it is kept molten, at approximately 140 °C, by steam coils. Sulphur accumulated in this reservoir is pumped to trucks or rail cars for shipment.

Any further conversion of the sulphur gases still contained in the gas mixture from the Claus furnace must be done by catalytic reaction. The gas mixture is therefore reheated by one of several means and is then introduced to the catalyst bed. The catalytic Claus reaction releases more energy and converts more than half of the remaining sulphur gases to sulphur vapour. This vapour is condensed while generating low-pressure steam and is removed from the gas mixture. The remaining gas mixture is reheated and enters the next catalytic bed. This cycle of reheating, catalytic conversion and sulphur condensation is repeated in two to four catalytic steps. A typical Claus sulphur recovery unit comprises one free-flame reaction stage, i.e. one furnace, and three catalytic reaction stages. Each reaction step converts a smaller fraction of the remaining sulphur gases to sulphur vapour.

If a three-stage or four-stage sulphur recovery unit cannot meet the required emission levels in the gas mixture obtained after the last catalytic reaction stage, i.e. in the so- called tail gas, further processing is required. This involves a so-called tail gas treatment unit (TGTU), which generally can be configured to perform dry bed processes and wet scrubbing processes. Wet scrubbing processes, such as the BSR/amine process of WorleyParsons include a front-end section to convert all of the sulphur compounds still contained in the tail gas back into hydrogen sulphide. After cooling, the hydrogen sulphide-containing tail gas is contacted with a solvent to remove the hydrogen sulphide, much like in a conventional gas treating plant. The solvent is then regenerated to strip out the hydrogen sulphide, which is then recycled to the upstream Claus sulphur removal unit for subsequent conversion and recovery.

So-called oxygen enrichment is, as mentioned, a well-known economic and reliable method of debottlenecking existing Claus sulphur recovery units with minimal capital investment. It can also eliminate the need for fuel gas co-firing in the reaction furnace, required to maintain the correct temperature for contaminant destruction, for example for destruction of benzene, toluene and xylenes (BTX) in the sour gas mixture.

Generally, higher temperatures are required to maintain a stable flame (above about 900 °C) and even higher temperatures of above about 1 ,100 °C are required to destroy BTX and/or ammonia (present in sour gas mixtures obtained in refineries). Whether or not a corresponding co-firing is required particularly depends on the hydrogen sulphide content of the sour gas mixture treated and whether a sufficient temperature and a stable flame can be obtained by burning the sour gas mixture alone.

The concept of oxygen enrichment entails replacing part or all of the air fed to the Claus furnace by oxygen-enriched air or pure oxygen. Correspondingly, the volumetric flow through the Claus sulphur recovery unit decreases, allowing more of the sour gas mixture to be fed to the system. This results in an increased sulphur production capacity without the need for significant modifications to existing equipment or major changes to the process plant pressure profile.

The application of oxygen enrichment is not limited to retrofitting or debottlenecking existing Claus sulphur recovery units, but can also have advantages in newly designed plants where the acid gas mixtures obtained are lean and contain benzene, toluene and xylenes. Such plants classically require feed gas and/or combustion air preheating and the use of fuel gas co-firing and have not, historically, been considered for oxygen enriched operation. However, also in such plants, the use of oxygen enriched technology results in a reduction in the physical size of all major equipment items and an associated, significant reduction in capital cost. Particularly, a large reduction in fuel requirements in co-firing in the Claus furnace and other units can be achieved and therefore more fuel, e.g. natural gas, can be used for other purposes or provided as a product of the whole plant.

A particular advantage of oxygen enrichment is, furthermore, that the tail gas downstream a tail gas treatment unit is less“diluted” with nitrogen from the combustion air classically used. If little or no additional nitrogen is introduced into the process, the main component of the sour gas mixture after desulphurisation, i.e. carbon dioxide, and other components like hydrogen can be recovered in a simpler and more cost-effective way, e.g. by cryogenic technology alone and without energy-intensive wet technology. Air separation units, irrespective whether they are based on cryogenic processes or adsorption processes, require compressors in order to process the air being used as feedstock. Claus sulphur removal units conventionally are operated by introducing ambient air through blowers into the Claus furnace in order to introduce the oxygen contained in ambient air as reaction component. In an oxygen enriched operation, at least a part of ambient air is exchanged for pure oxygen or a gas mixture which has a higher oxygen content than that of ambient air. For example, in oxygen enriched operation, pure oxygen or an oxygen enriched gas mixture can be mixed into an air flow blown into the Claus furnace by a blower, and the amount of air is reduced correspondingly, in order to maintain a defined mass flow. Alternatively, a blower is no longer used for introducing air to the Claus furnace and only oxygen or an oxygen enriched gas mixture can be used in order to provide oxygen for burning. In this case, the main blower conventionally providing air to the Claus furnace can be dispensed of. The much smaller air blowers for a reducing gas generator and a tail gas incinerator (if present, respectively) can be further reduced in size.

Particularly in the latter case, an air blower is not at all required during normal operation of the Claus furnace. Also in the former case, however, during normal operation less air has to be introduced into the Claus furnace, resulting in a smaller capacity demand for the blower. However, during start-up of the Claus sulphur removal process, a blower may still technically be required because the process is started up with ambient air and then gradually boosted by oxygen enrichment up to the desired level, e.g. up to 100% or at least 100% oxygen. Particularly, a corresponding plant must be warmed up before the main burner is ignited, in order to avoid thermal shock.

In order to do this, fuel gas will be burned with air (introduced with a blower) in the Claus furnace at start-up. Further, the introduced air, fuel gas and/or sour gas could be pre-heated using heat exchangers applying steam, which can also be done according to the invention. According to an advantageous embodiment as disclosed hereinbelow, instead of the blower a compressor of the air separation unit can be used.

In other words, during the operation of an oxygen enriched Claus sulphur removal process (“oxygen enriched,” as mentioned, also referring to an operation with pure oxygen), the blower capacity could be significantly reduced or the blower could entirely be dispensed with. However, for the start-up of the Claus sulphur removal unit, ambient air is still required and as such a blower can be installed or, as disclosed hereinbelow, a compressor of the air separation unit can be used.

The air separation unit used in the present invention is preferably dedicated to supply the oxygen to the Claus sulphur removal unit with the objective to operate the Claus sulphur removal unit on an oxygen enriched air or 100% oxygen basis. However, during the start-up of the Claus sulphur removal unit, no oxygen is required because, as mentioned, the oxygen content of the feed into the Claus sulphur removal unit will be gradually increased. During this period, the main air compressor being required for the air separation unit can be used, according to a preferred embodiment of the present invention, to provide the air flow into the Claus unit. The required air pressure level for the feed into the Claus sulphur removal unit, here referred to as feed pressure level, is between 0.5 to 3.5 barg (bar gauge pressure), which matches the air pressure providable by the main air compressor.

The air separation can be turned off at this stage of Claus sulphur removal unit start-up or could be run in a turndown mode in this preferred embodiment of the present invention. While the oxygen enrichment level into the Claus sulphur removal unit is gradually increased, the air volume required by the Claus sulphur removal unit may accordingly be reduced gradually and can be substituted by products of the air separation performed in the air separation unit. Therefore, the main air compressor can provide a gradually increasing air volume to the air separation process which in turn can provide gradually increasing amounts of air separation products. In contrast, a decreasing air volume is provided to the Claus sulphur removal unit until this is completely substituted by a product of air separation in the air separation unit. Usage of the main air compressor of the air separation as described means, however, that this main air compressor must be operated from some point during start-up of the plant.

Generally, an“air separation product” refers, in the language used herein, to any fluid which can be obtained by cryogenic or non-cryogenic air separation and which contains one or more components of ambient air in a higher or lower content than ambient air, i.e. which is enriched or depleted in the meaning above. Particularly, an air separation product as used in the context of the present invention is an oxygen rich or oxygen enriched air separation product or (essentially) pure oxygen. The“oxygen- containing gas” referred to hereinbelow is such an air separation product. Features and advantages of the invention

As mentioned before, the present invention is of particular advantage in connection with sour gas desulphurisation involving the Claus process, but equally suitable for other processes of sour gas desulphurisation.

The present invention provides an advantageous integration of air separation and sour gas desulphurisation. The present invention is based on the finding that a concerted activation of the different components used in a corresponding method allows for a particularly advantageous operation when a (main air) compressor which is operated by a steam turbine is used in the air separation process. If, in the following, general reference is made to a“compressor” used in an air separation process or plant, this is particularly intended to refer to the main air compressor.

A central aspect of the present invention is to recover compression heat of air which is compressed for subsequent separation in the air separation process and to use this heat in generating the steam used for operating the compressor. Particularly, the compression heat can be used, due to its heat level, to preheat boiler feed water which is converted into the steam in a steam generator. The term“steam generator” shall, in the language as used herein, refer to equipment for converting liquid water to steam and may include boilers, boiler feed water preheaters, steam heaters and superheaters and the like. All these components can be embodied as heat exchangers as known in the prior art or can be or at least include such heat exchangers.

A particularly important aspect of the present invention is the way in which a heat deficit which results from lacking compression heat during start-up of a corresponding method is compensated. The compression heat is particularly not available during start-up, at least during the beginning of a start-up sequence, because an air separation process is, as mentioned, only gradually started and because the compressor is only gradually powered up. The latter is also the result of technical constraints. In other words, while steam is required during such periods, no

compression heat used for its generation is initially available. Under a“start-up sequence,” a series of process states of a steady or dynamic nature shall be understood herein, the start-up sequence particularly including sequentially putting into operation several components used in the method. In contrast, in a time period subsequent to such a start-up sequence, the method utilizes the different components in a mostly steady state, this, however, not excluding changing set-points in the context of a control operation. The period subsequent to such a start-up sequence corresponds to a regular operation of the method or plant.

To compensate the heat deficit just mentioned, a steam generation system could generally be equipped with a heater capable of providing heat sufficient for start-up when the compression heat is not present. In other words, the steam volume required for the start-up of an air separation unit including a compressor driven by a steam turbine could generally be provided using an external boiler at scale that matches the required steam capacity for the main air compressor during start-up. However, once the air separation unit is fully operational, i.e. after the start-up sequence, the compression heat used for steam generation according to the present invention as indicated above can also be used to generate steam, and the full potential of the steam boiler which is required for start-up is no longer utilised. Operation of the steam boiler may thus become inefficient. Also providing a steam boiler which is essentially overdesigned for most of the time represents an unwanted investment.

According to the present invention, such a boiler can be designed with a smaller capacity, as explained in the following. Such a boiler can, according to the invention, generally be designed with a capacity that matches, but does not exceed, the required steam capacity for the main air compressor during regular operation wherein compression heat from the compressed air is also used in steam generation, particularly for pre-heating boiler feed water.

The capacity gap between steam requirements for air separation during start-up and during regular operation is filled according to the present invention using an existing start-up boiler which is particularly associated to the oxidative process for

desulphurisation. Such a start-up boiler, also referred to an“auxiliary” steam generator herein, is particularly used for pre-heating certain equipment used in the method during start-up, but conventionally not required during later regular operation. It can already exist in a corresponding plant for pre-heating equipment or it may be specifically installed for the process steps provided according to the present invention. The terms “start-up” and“auxiliary” steam generator (or boiler) are used synonymously herein. Equipment that may be heated accordingly particularly may include a pre-heating system used to pre-heat a sulfur treatment system in the oxidative process.

As mentioned, in a typical Claus process, the elementary sulfur produced is obtained in liquid form. Therefore, particularly components for handling such sulfur must be pre heated in order to avoid solidification when liquid sulfur contacts the still cold surfaces in the sulfur treatment system. However, also a number of other components may be pre-heated accordingly. Such components are mentioned throughout this description.

A start-up boiler or auxiliary steam generator as described provides, according to the present invention, steam for preheating components in an initial part of a start-up process or sequence and later on during the start-up sequence provides steam which is in turn used in providing or generating steam for operating the compressor of the air separation unit as explained in more detail hereinbelow.

In all embodiments of the present invention, due to the utilisation of the heat deriving from air compression in the manner explained above, the overall utility balance is improved significantly and capital and/or operating expenses of oxidative

desulphurisation are significantly reduced. An advantageous operation according to the present invention can be achieved without enlarging the steam generation system in order to cope with a reduced availability of compression heat.

According to the present invention, as repeatedly mentioned, compression heat of the air compressed in an air separation process is used in a steam generation system generating steam which is also used in the inventive method. The compression heat is particularly withdrawn between different compression stages of a main air compressor and/or downstream of the main air compressor or its last compression stage.

Particularly, according to the present invention, the compression heat is at least in part withdrawn from the air and is transferred using a heat transfer medium used in one or more cooling steps during or downstream of the (main) compression, absorbing the heat energy from the compression. This heat transfer medium is then particularly used to preheat water supplied to the steam generation system, i.e. to boiler feed water. Due to the preheating of the boiler feed water, less thermal energy is required to generate steam according to the present invention. If no compression heat is available during a start-up process, heat which is contained in steam that is provided by an auxiliary steam generator is used instead.

According to the present invention, the compression of air in the air separation process is performed using at least one compressor or compression stage using steam, i.e. such a compressor or compression stage is particularly driven using a steam turbine, and the steam from the steam generation system is at least in part used to operate the steam turbine. The steam which is used to drive the steam turbine is thus, in other words, at least in part (and at least during certain time periods) produced using heat from the air which is compressed using the steam turbine or, more precisely, a compressor or a compression stage driven thereby. Specifically, the main air compressor of an air separation plant used in the air separation process can be operated entirely using a steam turbine. Obviously, the compression heat is not the only heat source for steam generation but contributes to the total heat required therefor, e.g. in the context of preheating boiler feed water.

The method according to the present invention includes a start-up sequence as explained in detail hereinbelow. During the start-up sequence, a corresponding plant is not yet fully operational, as several components not yet operate or do at least not yet operate at full capacity. As further explained below, start-up of a corresponding plant entails subsequently activating or starting several plant components or parts.

The present invention can, in an illustrative example, be used in connection with an air separation unit with a production capacity of 106,000 Nm ³ /h (normal cubic metres per hour) at 2 bara (bars absolute pressure) with which no substantial amounts of other gaseous or liquid products are provided. The air separation process is optimised to minimise energy consumption and includes supply of the process air at two pressure levels. The main air compressor may be of the axial-radial type with a high isentropic efficiency in its axial stage. The steam demand of the main air compressor aspiring ambient air at e.g. 35 °C may be 150 t/h at 25 bara at a temperature of 450 °C.

This required steam massflow rate to drive the main air compressor corresponds to a similar feed water volume with a feed condensate temperature of 40.3 °C. Downstream of a heat exchanger used according to the present invention, the condensate exit temperature level is e.g. at about 165 °C. In other words, the exemplified method involves heating boiler feed water from 40.3 to 165 °C by utilising compression heat and allows to save around 15% of natural gas required for boiler operation (in the considered case with partial heat integration and a separate steam generator serving mainly the air separation unit).

In another case, the sulphur recovery unit used in this example may produce superheated high-pressure steam at 25 bara and 450 °C with a mass flow of about 900 t/h, saturated at 42 bara and 370 °C. Due to the heat integration between the air separation unit and the sulphur recovery unit according to the present invention, the sulphur recovery unit may produce an increased volume of high-pressure steam. The gain in steam mass flow in the present example could be up to 30 t/h and as such quite significant with reference to a steam flow required to operate the air separation unit. This steam can be at 25 bara and 450 °C.

The combination of both the high-pressure steam produced by sulphur recovery as well as high-pressure steam from the auxiliary steam generator can be also used to drive the main air compressor of the air separation unit. In other words, the auxiliary steam generator not necessarily is used for pre-heating boiler feed water but can also be used to generate steam at a matching pressure and temperature level which is combined with or admixed to the steam from the main steam generator. At any step of the inventive method, steam which is provided can also be fed into a steam grid which is present on-site, particularly by the auxiliary steam generator.

Gas processing plants and methods processing, particularly for treating sour natural gas, are rather complex and typically utilise various processing units such as e.g. acid gas removal units (e.g. so-called amine units in which an amine scrubbing is performed, as explained below), natural gas processing facilities (e.g. for so-called dewpointing or dehydration), sulphur removal units and tail gas treatment units as explained above. In such plants and methods, air separation units can be used not only to provide oxygen for the purposes as explained above but also to provide nitrogen for purging and blanketing. As to further details, reference is also made to the expert literature cited in the outset. Processes applied in such integrated processing plants and methods comprise sequential start-ups of the various processing units. Particularly if in one or some of these units waste-heat is produced, e.g. in a Claus process heat contained in the gas mixture processed in the Claus furnace, steam can be generated as a by-product, and this steam can be applied in another integrated units, i.e. in steam consumers.

Problems arise, in this context, if waste-heat generating units are or can be started up only after the steam consumers are started up and require steam for their functioning already. In corresponding integrated processes, a sulphur removal unit operating on the basis of the Claus process can be considered as steam exporter (in e.g. a refinery or gas processing plant) and this serves other processing units with steam during normal operation. However, such steam is not yet available during start-up of the Claus process or a corresponding unit.

As just mentioned, steam produced using waste-heat of the Claus process can e.g. be applied in an amine unit for the regeneration of the amine solvent. A typical amine gas treating process includes an absorber unit and a regenerator unit as well as accessory equipment. In the absorber unit, a downflowing amine solution absorbs hydrogen sulphide and carbon dioxide from an upflowing gas mixture to produce a“sweetened” gas stream as a product and an amine solution rich in the absorbed acid gases. The resultant“rich” amine is then routed into the regenerator unit representing a stripper with a reboiler to produce regenerated or“lean” amine that is recycled for reuse in the absorber unit.

An amine unit is typically used to sweeten natural gas and to provide sweetened natural gas (i.e. natural gas free of hydrogen sulphide and carbon dioxide). The stripped gas mixture from the regenerator unit of this amine unit is enriched or rich in hydrogen sulphide and carbon dioxide. It represents the sour gas mixture which can be treated (desulphurised) in the Claus process. In a tail gas treatment unit, residues of sour gases or intermediate products which were not fully converted to the target products, e.g. to elementary sulphur, may be removed in a further amine unit. The amine unit integrated in the tail gas treatment unit can be operated independently from the amine unit to which the natural gas is initially supplied. Particularly the reboiler of the regenerator unit of the amine unit can be operated with steam produced using waste heat of the Claus process. However, it will be understood that an amine unit, producing a sour gas which is to be treated in the Claus process, and thus supplying the gas to be treated to the Claus process, must be started up before the Claus process. However, at the time of the start-up of the amine unit, no waste heat from the Claus process is yet available. This problem is also present if other units in a corresponding integrated plant or method require steam, e.g. for heating purposes, which is not yet available at start-up.

A tail gas treatment unit can thus generally be considered to represent a steam consumer, wherein particularly during pre-heating and during start-up steam is required. Typically, by using waste heat from the Claus process, high and low pressure steam are produced. The tail gas treatment unit typically imports low pressure steam. Therefore, further steam can be produced and used for other purposes. In the

BSR/amine tail gas treatment technology mentioned above, a primary steam use is present in reboiling the amine solvent in the solvent regenerator, as mentioned.

Additionally, steam can be used to heat the tail gas to reaction temperature before it is introduced into the hydrogenation reactor. (The latter can, however, also be achieved by burning fuel gas in a“reducing gas generator”, RGG).

In integrated plants and methods of the kind described, conventionally a dedicated steam plant including a steam boiler which is typically fired by gas or oil is used which temporarily is producing steam to serve the consumers during the start-up phase of the plant, if no waste heat is yet available. This steam boiler may be the auxiliary steam generator as described herein. Once the complex including the sulphur recovery unit is fully started up, the steam balance is reached and as such the steam boiler typically can be turned down significantly or turned off as sufficient steam can be provided using waste heat from the sulphur recovery unit.

The present invention may use, according to a preferred embodiment and during the start-up sequence, instead of steam from a dedicated steam plant or boiler, steam which is provided in a further steam plant or boiler which is used for driving one or more compressors, particularly the main air compressor, in an air separation unit which is also part of the integrated plant or method.

The air separation unit may, as mentioned in the outset, be a cryogenic or non- cryogenic air separation unit comprising a corresponding compressor. The steam plant or boiler associated with the air separation unit may, according to the invention, be started up first to supply other gas processing units like the amine unit temporarily with steam during their start up, while no waste heat is yet available from e.g. the Claus process. When the latter is readily started up and beginning to export steam, the steam boiler will start to serve steam to start up and later continuous operations of the air separation unit instead. These concepts can obviously be transferred to other oxidative processes as well. Such an operation may be possible due to a smaller steam demand of the steam turbine during the start-up sequence.

Detailed description of the invention

In view of the above, the present invention provides a gas treatment method including an oxidative process for desulphurisation of a sour gas mixture, and including an air separation process supplying an oxygen-containing gas to the oxidative process, wherein air is compressed in the air separation process by means of a compressor operated using steam. The method comprises a start-up sequence used to sequentially put into operation the oxidative process and the air separation process as described above. According to the present invention, the start-up sequence (at least) includes a first, a second and a third time period. Further time periods can be included as well and may include further operation modes, as explained hereinbelow. For the avoidance of misunderstandings, the first, second and third time period are non-overlapping time periods in the sequence as expressed by their enumeration, but in between these time periods further time periods may be present.

According to the present invention, in the first time period a first amount of steam is provided and the first amount of steam is used to preheat equipment used in the process. The equipment which is pre-heated in the first time period is particularly used in the oxidative method, e.g. a Claus process. Such equipment can particularly include a Claus furnace and catalytic reactors used for converting sulphur dioxide. It can also include components of a tail gas treatment unit as indicated above. Equipment which is pre-heated in this way in the first time period can also be a steam turbine driving the compressor of the air separation unit which, after pre-heating in the first time period, is coupled to the steam turbine and gradually powered up thereafter. For example, in order to avoid solidification of liquid sulfur which is obtained in the oxidative process or, more precisely, in the catalytic reactor(s) subsequently thereto, such a preheating needs to be performed. In the further course of the process, where substantial amounts of waste heat are generated, no such heating is required and therefore no steam needs to be provided. An auxiliary steam generator unit which is provided for preheating the equipment mentioned can therefore be used to provide steam for the steam turbine or can be used in order to support steam generation in a main steam generator, e.g. by means of pre-heating of boiler feed water. Such steam can, however, also be fed into a steam grid from which the system can be supplied with steam. Pre-heating of boiler feed water is in later time periods performed via compression heat, and the operation of the auxiliary steam generator can be suspended.

That is, according to the present invention, in the second time period a second amount of steam is provided and the second amount of steam is used to (at least partially) drive the compressor. Thereafter, in the third time period, a third amount of steam is provided and the third amount of steam is used to drive (at least partially) the compressor. At least in the second and third time period, a main steam generator is used in providing the second and the third amount of steam, and at least in the first and second time period, an auxiliary steam generator is used in providing the first and the second amount of steam. Furthermore, in the third time period, compression heat of the air compressed in the compressor is used in providing the third amount of steam as described before. In other words, according to the present invention, initially the auxiliary (or“start-up”) steam generator is used, and thereafter, if available, steam is instead produced including compression heat.

In yet other words, according to the present invention, the auxiliary steam generator is used, in the first time period, predominantly or exclusively to preheat the equipment used in the process, and, in the second time period, predominantly or exclusively in providing steam (particularly in form of as a part of the second amount of steam) to drive the compressor in compensation for steam generated from the compression heat which is available in the third time period and is not available, or available in a lower amount, in the second time period. A "predominant" use of the auxiliary steam generator shall refer to a use of at least 75%, 80% or 90% of the steam generated by the auxiliary steam generator for the purpose mentioned. An "exclusive" use may particularly refer to a use of all the steam generated. The start-up sequence can again be summarized as follows. In the first time period, equipment is pre-heated, e.g. components used in the oxidative process and/or components like the compressor used in the air separation process. In the second time period, the main steam generator is also used already. This main steam generator can be operated with waste heat of the oxidative process which now may be in operation or may start to operate, and thus represents a steam exporting unit. In an initial period of the second time period, the compressor already is driven by steam but not necessarily must supply the air separation process with compressed air yet. Alternatively, in this initial period of the second time period, compressed air may also be used to supply the oxidative process which is thus initially operated without oxygen enrichment. With the temperature and steam amount raising in the second time period, however, the air separation process may be supplied with compressed air and may correspondingly produce increasing amounts of the oxygen-containing gas which then can gradually substitute the air which is previously provided to the oxidative process. Thus, two sub periods may be included in the second time period, i.e. a first sub-period in which the air separation process is not yet producing air separation products and the oxidative process is operated in a non-enriched manner, and a second sub-period in which the air separation process is producing increasing amounts of air separation products and in which the oxidative process is operated in a gradually enriched manner. In the third time period, when the system is essentially fully operational, the compression heat is used in steam generation. The third time period may also essentially correspond to a subsequent operation mode.

If, at any place of this description, reference is made to an“amount” of steam, waste- heat, fluid, oxygen-containing gas or the like, this refers to an amount per a certain period of time, which is, if such amounts are compared to each other, an identical period of time for both cases. Particularly, such amounts can be expressed in standard units, i.e. related to standard conditions of pressure and temperature.

In the language as used herein, use of a steam generator or of heat“in providing” a certain amount of steam is meant to refer to any utilization of such steam conceivable. For example, such a steam generator or such heat can be used as a part of the amount of steam, i.e. it can be combined with further proportion of steam, or heat of steam generated by such a steam generator can be used in a different steam generator, e.g. for pre-heating boiler feed water and/or for heating steam generated in the further steam generator. Particularly, in the present invention, as mentioned, the auxiliary steam generator which is used to perform pre-heating of equipment in the first time period via steam is used in providing the first and second amount of steam by using the steam generated for pre-heating boiler feed water which is used for generating the second amount of steam. As also mentioned, in the third time period, compression heat of the air compressed in the compressor is likewise used in providing the third amount of steam by pre-heating of boiler feed water. Steam can also be supplied to a steam grid which can provide steam to different parts of the plant used according to the present invention and to different plants, as described. If steam is withdrawn from such a steam grid for a certain unit, the steam generator which supplies steam to the steam grid is used in providing this steam.

In other words, the gas treatment method preferably includes that boiler feed water is provided to the main steam generator in the second and third time period, wherein the boiler feed water is preheated at least in the third time period. Particularly, using the compression heat in providing the third amount of steam in the third time period comprises preheating the boiler feed water using the compression heat. Using the auxiliary steam generator in providing the second amount of steam in the second time period may comprise preheating the boiler feed water using at least a part of the steam provided by the auxiliary steam generator, and/or combining such steam at least in part with the steam provided by the main steam generator.

For the avoidance of misunderstandings, the first, the second and the third amount of steam can be equal or different. Particularly, the first amount of steam may be smaller than the second and the third amount of steam. The first, the second and the third amount of steam are not necessarily required to be constant, i.e. the second amount of steam can be increased over the second time period, in order to gradually power up the steam turbine and/or the compressor driven thereby, corresponding to the increasing amounts of waste heat available.

The present invention is particularly advantageous in connection with oxygen-enriched Claus processes because such processes are, as mentioned, typically started up with ambient air and then gradually boosted by oxygen enrichment of up to 100% oxygen up to the desired sulphur capacity level of e.g. up to 250% as compared to a non- enriched operation. This staged start-up could be e.g. done to heat up the process equipment and to avoid thermal shock. Therefore, when starting up the Claus process, oxygen or oxygen enriched air from the air separation unit is not yet required in the Claus process and the compressor(s) of the air separation unit are not yet needed. A steam plant or boiler for supplying steam to the compressor(s) of the air separation unit can instead be used to supply steam to further gas treatment units as mentioned.

However, already from start-up of the Claus process, also if this is still supplied with ambient air, waste heat is present. As mentioned, in order to do avoid thermal shock, fuel gas will be burned with air in the Claus furnace at start-up. Such waste heat can be used in the second time period, as explained in detail before.

As no air from the air separation unit is thus required during start-up of the oxygen- enriched Claus process, the air separation unit can be started after the units used in the Claus process have been pre-heated and the Claus process was started (and is initially operated with air). During this initial period, or during the“second” time period of the start-up sequence according to the present invention, the air separation unit can be gradually started up, wherein steam from the auxiliary steam generation unit (which, as mentioned, can be a“start-up boiler” already present in an existing plant or a dedicated steam generation unit) is also used in providing the steam for the compressor.

In the context of the method in which the present invention is used, initially steam may be used to pre-heat a steam turbine system which is used to drive the compressor, in order to uniformly warm the steam turbine rotor and casing, involving a still relatively small steam flow. This may correspond to the first time period mentioned. The compressor which is driven by the steam turbine, e.g. the main air compressor of an air separation unit, is then coupled to the steam turbine and is gradually powered up to a minimum turndown at e.g. about 60 to 70% of the maximum speed or the regular operational speed. The steam demand proportionally increases in this course. This step may correspond to the second time period mentioned. In the minimal turndown operation, the air separation unit can start to provide the oxygen-containing gas to the oxidative process. The oxygen content or amount used in the oxidative process is gradually increased until production and its use in the oxidative process are equal. If, in this context, the amount of oxygen-containing gas is too high, it can also be vented to the atmosphere or stored for later use. Reference is also made to the explanations regarding the first and second sub-periods of the second time period mentioned above. Subsequently, in a time period corresponding to the third time period mentioned, the oxydative process and the air separation process can be gradually further powered up until a maximum performance is reached. In the third time period, sufficient

compression heat is already available in order to contribute to steam generation.

The sour gas mixture desulfurised in the method according to the present invention may particularly be a lean sour gas mixture, i.e. a sour gas mixture containing less than 80%, less than 60% or less than 50% and more than 10%, more than 20%, more than 30% or more than 40% of hydrogen sulphide. The present invention is particularly advantageous in this context, because lean sour gas mixtures comprise less oxidable components and therefore waste heat is produced to a smaller extent than in the case of rich sour gas mixtures. Therefore, a careful waste heat management is important, which is provided for according to an advantageous embodiment of the invention.

According to a particularly preferred embodiment of the present invention, the sour gas mixture and the oxygen-containing gas are introduced into an oxidation unit. The sour gas mixture is, for reference purposes only, referred to as a“first” gas mixture, i.e. the sour gas mixture is provided as this first gas mixture. In the oxidation unit, the sour gas mixture is desulphurised, i.e. an oxidable component in the first gas mixture is oxidised in the oxidating unit, providing waste heat. A gas mixture used in providing the sour gas mixture is, for reference reasons only, also referred to as a“second” gas mixture. The second gas mixture may e.g. be natural gas. A gas mixture produced from at least a part of the sour gas mixture in the oxidating unit, i.e. a gas mixture particularly depleted in hydrogen sulphide, is referred to for reference purposes as a“third” gas mixture. The sour gas, i.e. the first gas mixture, and/or the second gas mixture used in providing the first gas mixture and/or the third gas mixture produced from at least a part of the first gas mixture by using the oxidation unit is or are treated in one or more gas treatment units which are operated using further steam,“further steam” referring to an amount of steam not used as the first, second and third amount of steam referred to before or as a part thereof. However, the“further steam” may generally also be provided in the main and/or the auxiliary steam generator referred to above which are used in providing the first, second and/or third amount of steam in the manner described.

During a start-up operation including the start-up sequence according to the present invention described before, and therefore during at least a part of the startup sequence, at least a part of this further steam may be provided using heat other than waste heat of the oxidating unit or a sub-unit thereof, and in a regular mode of operation subsequent to the startup sequence, at least a part of this further steam may be provided using waste heat of the oxidating unit or a sub-unit thereof. The oxidation unit may include a furnace, a catalytic unit subsequent thereto, or a tail gas treatment unit, particularly including a further burner. Each of these sub-units is capable of providing waste heat utilisable in the context of the present invention.

In any embodiments of the present invention, said operating the compressor using the steam may comprise expanding the steam in a steam turbine which is mechanically coupled to the compressor. This means that a direct transfer of rotational energy output by the steam turbine to the compressor is present, according to the present invention.

A mechanical coupling as used according to the present invention may include a coupling including equal speeds of a driving shaft of the steam turbine and a driven shaft of the compressor, or a coupling via a transmission or gearbox resulting in fixed or variable speed differences. A mechanical coupling does not comprise, according to the present invention, an indirect coupling in which, for example, rotational energy from the steam turbine is converted to a different form of energy like electrical energy and wherein the different form of energy is converted to rotational energy in order to drive the compressor. Such an operation may, however, also be present, according to the present invention A mechanical coupling, which may be provided according to the present invention, eliminates energy conversion losses otherwise present.

As mentioned, operating the compressor using steam may comprise, in other words, expanding the steam in a steam turbine which is mechanically coupled to the compressor. However, this does not exclude that operating the compressor may also comprise using supplementary energy which is not provided in the form of steam expanded in the steam turbine.

According to an embodiment of the present invention, furthermore, generating further steam during at least a part of the start-up sequence may be done using heat other than waste heat and may be performed using a non waste heat steam generator.

Generating at least a part of this further steam subsequent to the start-up sequence may be done using waste heat of the oxidating unit or a sub-unit thereof and may be performed using a waste heat steam generator. The non waste heat steam generator and the waste heat steam generator may be steam generators separate from the main and the auxiliary steam generator described before. However, said generating at least a part of the further steam during at least a part of the start-up sequence, which is done using heat other than waste heat of the oxidating unit, and said generating at least a part of the further steam subsequent to the start-up sequence, which is done using waste heat of the oxidating unit or a sub-unit thereof, may also be performed using any other steam generators, a common steam generator, or a steam generation system including any of the steam generators mentioned.

In the method according to the embodiment of the present invention just described, at least a part of the further steam which is provided by the non waste heat steam generator during at least a part of the start-up sequence may be instead provided by the waste heat steam generator subsequent to the start-up sequence, and a total amount of steam smaller than the an amount of steam during at least a part of the start-up sequence, or no steam, may be provided by the non waste heat steam generator subsequent to the start-up sequence. Likewise, at least a part of the further steam provided by the waste heat steam generator subsequent to the start-up sequence may instead be provided by the non waste heat steam generator during at least a part of the start-up sequence, and a total amount of steam provided by the waste heat steam generator subsequent to the start-up sequence, or no steam, may be provided by the non waste heat steam generator during at least a part of the start-up sequence. The waste heat steam generator may thus be operated only in cases in which waste heat is available, i.e. during start-up, or vice versa. In this connection, the non waste heat steam generator, which may in at least a part of the start-up sequence be used in providing the further steam, may be used to operate the at least one gas treatment unit thereafter.

Particular advantages and further features of the embodiment of the present invention just referred to have already been discussed before. Particularly, through the integration of an oxidative process, e.g. the Claus process, the capital expenses (CAPEX) and also the operating expenses (OPEX, especially repair and maintenance cost) for the overall process can be reduced, as an additional (only temporarily used) steam boiler (capacity) is avoided or the steam generator for operating the air separation unit may be designed smaller. Furthermore, according to embodiments of the present invention, the start-up of a corresponding method is simplified as due to less equipment a reduced schedule is possible. Furthermore, according to the present invention, less plot space is required. Steam-driven air separation units are,

furthermore, usually more cost efficient considering the total cost of ownership. As such the overall economics of an oxygen-enriched Clauss process are improved.

It is generally not excluded in embodiments of the present invention that waste heat is also generated during at least a part of the start-up sequence. However, the amount of this waste heat may be smaller than an amount of waste heat provided subsequent to the start-up sequence. In other words, the oxidative process may be providing waste heat in a smaller waste heat amount during at least a part of the start-up sequence and may be providing waste heat in a larger waste heat amount thereafter, i.e. subsequent to the start-up sequence.

As also discussed before, the present invention advantageously is used in connection with the Claus process and a corresponding gas treatment. Therefore, advantageously, the first gas mixture is a sour gas mixture, the oxidable component is hydrogen sulphide, the oxidative process is a Claus process, the oxidating unit is a Claus furnace, and a part of the hydrogen sulphide in the sour gas mixture is oxidised by free- flame oxidation in the Claus furnace. For particular advantages, also for this preferred embodiment reference is made to the explanations above.

The air separation unit can provide, as also mentioned, oxygen or oxygen enriched air to the Claus process or its furnace or to another oxidative process. A preferred method according to the present invention therefore includes that the oxygen-containing gas is provided as an air separation product, and the air separation product is pure oxygen or a mixture of components enriched in oxygen as compared to atmospheric air.

The method of the present invention may, according to a preferred embodiment, also include an operation mode in which the air separation process may not be in operation during a partial period of the start-up sequence while being in operation during a remainder of the start-up sequence. Likewise, also during later periods, the air separation process may not be in operation while it regularly is. In such an operation mode, i.e. when the air separation process is not in operation, which may also be an emergency or suspended operation mode, e.g. during a period of power loss or during maintenance, the oxidative process may be provided with unenriched air instead and the oxidative process, in this operation mode, may be operated without oxygen enrichment. This allows for situations in which the air separation process may not be available, e.g. due to maintenance or as a result of an emergency shut-down of the air separation process. Advantageously, in such cases the oxidative process can be, with an impaired efficiency, however, operated continuously, eliminating the need for shutting down and later re-starting the oxidative process. As mentioned before, during start-up, also such an operation is contemplated.

Generally, the air separation product has an oxygen content higher than that of ambient air. It may comprise at least 30%, 40%, 50%, 60%, 70%, 80%, 90% or 95% oxygen by volume. In other words, different levels of oxygen enrichment are possible. Also, essentially pure oxygen may be used. The air separation unit may also provide partly enriched oxygen products depending on the specific requirements of the Claus sulphur removal unit, and thus the energy consumption of the air separation unit can be optimised accordingly. Particularly, a cryogenic air separation unit including a mixing column can be used for this purpose, as e.g. described in EP 3 179 187 A1 and the references cited therein.

Particularly preferably, a larger amount of the air separation product is produced by the air separation unit subsequent to the start-up sequence, and a smaller amount of the air separation product or none of the air separation product is produced by the air separation unit during at least a part of the start-up sequence. In other words, during start-up of the inventive method, operation of the air separation unit can be fully or partially suspended. This is also the case for later periods in which the air separation process may not be in operation, particularly as described before.

According to a particularly preferred embodiment, only a part of the amount of the air separation product which is produced subsequent to the start-up sequence is introduced into the Claus furnace subsequent to the start-up sequence, and a further part of the air separation product is at least temporarily stored and is at least in part introduced into the Claus furnace in during a subsequent start-up sequence. In other words, also in the start-up mode, oxygen or oxygen-enriched air may be supplied to the oxidative process from oxygen or oxygen-enriched air which is produced in the normal operation mode and is e.g. stored in a back-up tank. In this case, particularly liquid oxygen can be used. This provides the benefit that already during start-up, already at least some oxygen-enrichment can be performed. Again, such an embodiment allows an air separation unit to operate at reduced capacity during start-up, in order to reduce the steam demand correspondingly during start-up.

Generally, e.g. a Claus furnace temperature in the sulphur recovery unit can, according to the present invention, be further increased by using additional oxygen and as such a larger steam quantity can be exported. As such, the overall steam balance can be optimised. In case this additional steam produced by the delta of a conventional air based Claus process and the oxygen-enriched process is not utilised by the other process units, this excess steam could be utilised to run the steam drives of the air separation unit, at least partially. This means from an operational perspective that during the start-up phase of the sulphur recovery unit the air separation may be run on less steam (produced from or independently from waste heat) in a turn down mode first. When increased steam is available from the sulphur recovery unit (due to oxygen enrichment) the air separation unit can be operated at 100%. As such a steam boiler size could be optimised.

According to an embodiment of the present invention, the third gas mixture produced from at least a part of the first gas mixture using the oxidating unit, which was already referred to above, can be treated in a tail gas treatment unit. As explained in more detail above, a tail gas treatment unit generally represents a steam consumer, but may nevertheless be providing waste-heat, e.g. if it comprises a further furnace. Therefore, the tail gas treatment unit can be operated using the further steam referred to hereinbefore, in order to heat the tail gas to reaction temperature before it is introduced into a hydrogenation reactor in the tail gas treatment unit, or a loaded amine solution can be regenerated using heat from the further steam mentioned hereinbefore, or a part thereof. For further details, reference is made to the explanations above.

As mentioned, the present invention can also be used with an amine unit as explained above in order to treat a second gas mixture used in order to produce the first gas mixture. As also mentioned, also a tail gas treatment unit adapted to treat the third gas mixture mentioned, or a part thereof, can comprise an amine unit. In other words, advantageously the second gas mixture used in providing the first gas mixture and/or the third gas mixture produced from at least a part of the first gas mixture is treated in the or one of the gas treatment units, wherein the second and/or the third gas mixture is a gas mixture containing hydrogen sulphide and carbon dioxide, wherein the gas treatment unit or the one of the gas treatment units comprises an amine unit (or amine wash unit), wherein in the amine unit hydrogen sulphide and carbon dioxide are at least partially eliminated from the second and/or the third gas mixture using an amine solution and forming an amine solution loaded with hydrogen sulphide and carbon dioxide, and wherein the hydrogen sulphide and the carbon dioxide are at least in part stripped from the loaded amine solution using heat from the first amount of steam or a part thereof. Particularly, two gas treatment units, each including an amine unit, can be provided in order to treat the second or the third gas mixture, respectively.

The present invention also relates to an apparatus for performing a gas treatment method as set forth in the corresponding independent apparatus claim, which is not recited herein for reasons of conciseness.

As to specific further features and embodiments of such an apparatus, reference is made to the explanations above relating to the method according to the invention and its advantageous embodiments. This equally applies for a corresponding apparatus which is adapted to perform a corresponding method or one of its embodiments. Such an apparatus may particularly include a control unit programmed or adapted to control the units of the apparatus in order to particularly perform the start-up sequence.

The present invention will further be described with reference to the appended drawings which relate to a preferred embodiment of the present invention.

Short description of the drawings

Figure 1 schematically illustrates a gas treatment method including an oxidative process for desulphurisation of a sour gas mixture in general.

Figure 2A schematically illustrates a gas treatment method including an oxidative process for desulphurisation of a sour gas mixture in a first mode of operation.

Figure 2B schematically illustrates the gas treatment method according to Figure 2A in a second mode of operation. Figure 3A schematically illustrates a gas treatment method including an oxidative process for desulphurisation of a sour gas mixture according to an embodiment of the present invention in a third time period of a start-up sequence.

Figure 3B schematically illustrates the gas treatment method according to Figure 3A in a second time period of a start-up sequence.

Figure 3C schematically illustrates the gas treatment method according to Figure 3A in a first time period of a start-up sequence.

Detailed description of the drawings

In the Figures, functionally or technically identical or equivalent components are indicated with like reference numerals and not repeatedly explained for sake of conciseness. If explanations with regard to methods are given, these relate to the corresponding apparatus in the same manner.

Figure 1 schematically illustrates a gas treatment method including an oxidative process 4 for desulphurisation of a sour gas mixture in general. The process is illustrated as using a gas from an air separation process and is further illustrated to include a Claus process as the oxidative process 4. However, as repeatedly

mentioned, also other oxidative processes 4 for desulphurisation can be used in the context of the present invention.

A sour natural gas stream a from a gas field 1 is introduced into an sour gas removal unit 2, in this particular case including an amine unit 21 as mentioned before. The amine unit 21 is operated as generally known in the art, in the present example using a steam stream b which is used to heat a reboiler in the amine unit 21 (not shown). A steam stream c of a lower temperature or a condensate stream c can be formed.

A sweetened gas stream d is withdrawn from the acid gas removal unit 2 and optionally subjected to further treatment 3, providing a further treated gas stream e which can e.g. fed into a gas pipeline. A sour gas stream f is also withdrawn from the acid gas removal unit 2 and is introduced into the oxidative process 4 which is embodied as a Claus process 4, or, more specifically, into a Claus furnace 41 in the Claus process 4 which was hereinbefore also referred to as a“oxidation unit” 41 or a part thereof. The Claus process 4 may include further components. A part of the sour gas stream f can also be reinjected into the gas field 1 , as indicated by a dotted arrow in Figure 1. A sulphur stream g is withdrawn from the Claus process 4 and is subjected to a sulphur product handling 5. From this, a sulphur product stream h is withdrawn or otherwise provided.

In a tail gas treatment unit 6, which may in all embodiments of the present invention be a unit independent from the oxidative process 4 itself or from a corresponding unit, a tail gas stream i also withdrawn from the Claus process 4 is treated in a manner known per se. The tail gas treatment unit 6 provides a purified stack gas stream k with little or no sulphur compounds. Components from the tail gas treatment unit 6 can also, as illustrated with a dashed arrow, be reintroduced into the Claus process 4 or its Claus furnace 41. The tail gas treatment unit 6 may also comprise a unit operable by heat, e.g. an amine unit 61 , wherein the heat is provided in the form of steam. However, other units besides amine units may be present as well, like preheating units heating the tail gas stream i to reaction temperature, etc. A steam stream b' is provided to this unit and a steam stream c' of a lower temperature or a condensate stream c can be formed. One or both of the amine unit 21 in the acid gas removal unit 2 and the unit 61 in the tail gas treatment unit 6 may be provided and/or one or both of them may be operated using steam.

The Claus process 4 is operated with oxygen-enrichment in a regular operation mode. Therefore, using an air separation unit 7, an oxygen-containing gas, i.e. an oxygen stream or an oxygen-enriched stream I is provided which is also introduced into the Claus process 4 or its furnace 41. The air separation unit 7, which also may provide a nitrogen or nitrogen-enriched stream and other products and to which air is supplied (not shown), comprises a compressor 71 operated with a steam driven turbine 72 receiving a steam stream m. The turbine 72 is mechanically coupled to the compressor 71. A steam stream n of a lower temperature or a condensate stream n can be formed. The steam or condensate streams c, c’ and n can be reused for steam production.

Figure 2A schematically illustrates a gas treatment method 100 including an oxidative process 4 for desulphurisation of a sour gas mixture in a regular mode of operation which is performed subsequent to a starting sequence. Additional to Figure 1 , a first (waste heat) steam generator 10 and a second (non waste heat) steam generator 20 are shown in Figure 2A and 2B. The first steam generator 10 is shown in proximity to the Claus process 4 (but does not necessarily have to be located in proximity to the Claus process 4). It is operated using at least a part of the waste heat of the Claus process 4. The second steam generator 20 is shown in proximity to the air separation unit 7 (but does not necessarily have to be located in proximity to the air separation unit 7). It is operated independently from the waste heat of the Claus process 4. The second steam generator 20 can also be installed remotely from the air separation unit 7 and may be operated independently therefrom.

In the first mode of operation shown in Figure 2A, the gas treatment unit 2, or, more precisely, the amine unit 21 , and/or the tail gas treatment unit 6, or, more precisely, the unit 61 , is operated using steam in a certain amount which is provided by the first steam generator 10 operated using at least a part of the waste heat of the Claus process 4. As shown in Figure 2A, the steam stream b is correspondingly provided by the first steam generator 10.

In the first mode of operation shown in Figure 2A, the compressor 71 of the air separation unit 7 is also operated using steam in the steam turbine 72 which is mechanically coupled to the compressor 71 , this steam being provided by the second steam generator 20. As shown in Figure 2A, the steam stream m is correspondingly provided by the second steam generator 20.

In the mode of operation shown in Figure 2B, which corresponds to at least a part of a startup sequence, steam provided by the first steam generator 10 in the first mode of operation as shown in Figure 2B, is instead provided by the second steam generator 20 (see steam stream b, wherein this is also possible for steam stream b' but not shown for reasons of clarity). No steam is provided by the first steam generator 10. No steam is, furthermore, provided to the steam turbine 72 mechanically coupled to the compressor 71 of the air separation unit 7 and the air separation unit 7 is not in operation in the startup sequence in this example. It is, however, likewise possible to provide stream to the steam turbine 72 by the second steam generator 20 or any other steam generator. The heat recovered from the Claus process 4 is typically from two different sources.

The heat recovered from the Claus furnace 41 can be high pressure steam (HP steam). This can be up to 45 barg and is suitable for re-heating of the acid gas before entering the catalytic reactors and for driving turbines (it can also be superheated in the stack from the incinerator). Low pressure steam (LP steam) is generated in the sulphur condensers; this can be used to reboil the solvent in the amine unit(s) but is not suitable for driving turbines.

Figure 3A schematically illustrates a gas treatment method including an oxidative process for desulphurisation of a sour gas mixture according to an embodiment of the present invention in a time period of a startup sequence previously referred to as the “third” time period in which compression heat is available. Figure 3B schematically illustrates the gas treatment method according to Figure 3A in a mode of operation corresponding to the“second” part of the startup sequence referred to hereinbefore. Figure 3C schematically illustrates the gas treatment method according to Figure 3A (and 3B) in a mode of operation corresponding to the“first” part of the startup sequence referred to hereinbefore.

The process shown in Figures 3A, 3B and 3C is denoted 200. It may utilise all of the components as previously explained in relation to Figures 1 , 2A and 2B. Details are omitted for conciseness only, and in order to avoid repetitions. Particularly, the elements 1 to 6 are shown in a strictly simplified way, and only selected fluid streams are shown in Figures 3A, 3B and 3C. The first, second and third time periods are illustrated in reversed order in Figures 3A, 3B and 3C only in order to better explain the differences therebetween, while in practice these time periods are arranged in the order of their enumeration, as mentioned.

Of the air separation unit 7, the steam turbine 72 and the compressor 71 are shown in more detail in Figures 3A, 3B and 3C. In the compressor 71 , a stream o of atmospheric air is compressed, obtaining a compressed air stream p which is cooled in one or more coolers 73, obtaining a cooled, compressed air stream q, and then subjected to an arbitrary number of further steps 74, e.g. to purification, further cooling and rectification. This is the case for the third and the second time periods shown in Figures 3A and 3B. Between compression stages of the compressor 71 , further coolers may be present which can be operated like the cooler 73. Ultimately, the air separation unit 7 provides the oxygen or oxygen-enriched stream I which was already referred to before.

The cooler 73 is operated using one or more streams r of a heat transfer medium, via which compression heat is at least in part withdrawn from the air of the compressed air stream p in the third time period shown in Figure 3A. The heat is transferred to a steam generation system, which may include the steam generator 10 or 20 as already described before, or a further steam generator 30. Particularly, the compression heat is used to feed boiler feed water in a boiler feed water heater 11 in such a steam generation system. A steam generator 10, 20, 30 used accordingly is also referred to as a“main” steam generator hereinbefore.

The steam generation system or the steam generators 10, 20 or 30 may provide steam in form of the steam stream m to the steam turbine and/or further steam streams b, b' to any of the other components shown, as explained with reference to Figures 1 , 2A and 2B before. The streams c, c' shown in Figures 1 , 2A and 2B, which are formed herein as well are omitted for conciseness. Be it noted that several steam generators 10, 20 and 30 may operate accordingly and the block indicated with 10, 20, 30 in Figures 3A, 3B and 3C is only shown as one entity for reasons of conciseness herein.

In the second time period of the start-up sequence shown in Figure 3B, no

compression heat is yet available as compared to the third time period of the start-up sequence shown in Figure 3A and no such compression heat is thus transferable via the heat transfer medium stream r, as indicated by a dashed line. However, the steam turbine 72 is also in operation here and sufficient steam can be provided via the operation of a further steam generator 40 in this case, which is referred to as an “auxiliary” steam generator. Instead of a further steam generator 40 which may be operated by a firing, also e.g. the steam generator 20 can be used which may comprise an additional firing. In this case, the steam generator to which the compression heat is transferred in the first mode of operation may be a steam generator different from the steam generator 20. The steam generator 40 may also, instead of supplying steam directly to the steam turbine 72, used in order to pre-heat boiler feed water in the steam generators 10, 20 and/or 30. In the first time period of the start-up sequence shown in Figure 3C, also no compression heat is yet available as compared to the third time period of the start-up sequence shown in Figure 3A and thus such no compression heat is transferable via the heat transfer medium stream r, as indicated by a dashed line again. The steam turbine 72 may not be in operation here and no air may be compressed in the compressor 71 , as also indicated by dashed lines. The further steam generator 40 which may be operated like before, provides steam in order to pre-heat components of the process 200 as indicated before.