AU2016236357A1

AU2016236357A1 - Process for producing a purified gas stream from natural gas wells

Info

Publication number: AU2016236357A1
Application number: AU2016236357A
Authority: AU
Inventors: Anastasia ANGELOPOULOU; Thomas Médart De Cazenove; Menno Bastiaan Hendriks Gierman; Jeanine Marie Klinkenbijl; Shelby Carley McFarlin
Original assignee: Shell Internationale Research Maatschappij BV
Current assignee: Shell Internationale Research Maatschappij BV
Priority date: 2015-03-20
Filing date: 2016-03-17
Publication date: 2017-10-12
Anticipated expiration: 2036-03-17
Also published as: WO2016150827A1; AU2016236357B2; EA038262B1; EA201792081A1

Abstract

The invention relates to a process for producing a purified gas stream from a feed gas stream comprising natural gas, carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, xylenes. In the process the feed gas stream is contacted with absorbing liquid comprising sulfolane and a secondary or tertiary amine in an absorption column. The temperature of the absorbing liquid is reduced at an intermediate section of the absorption column. A loaded absorbing liquid and a depleted gas stream are obtained. Optionally the gas stream is cooled and de-pressurized, and flash gas is obtained. A single stage flesh vessel can be used, while it is not necessary to use a scrubber or de (m)ethanizer. Flash gas comprising less than 3 ppmv BTEX can be obtained. This flash gas can be subjected to liquefaction to obtain LNG.

Description

PROCESS FOR PRODUCING A PURIFIED GAS STREAM FROM NATURAL

GAS WELLS

Field of the invention

The invention relates to a process for producing a purified gas stream from a feed gas stream comprising contaminants .

Background to the invention

Gas streams from natural gas wells typically comprise contaminants such as carbon dioxide, hydrogen sulphide, and aromatic hydrocarbons such as benzene, toluene, ethylbenzene, and xylene that need to be removed before the gas streams can be further used.

Processes for removing hydrogen sulfide, carbon dioxide and aromatic hydrocarbons from a gas stream are known in the art. Such processes typically comprise an absorption step for removing hydrogen sulfide, carbon dioxide and aromatic hydrocarbons from the gaseous feed stream by contacting such gaseous feed stream with a solvent, for example an amine solvent, in an absorption column. Thus a purified gaseous stream is obtained and a solvent loaded with contaminants. The loaded solvent is typically regenerated in a stripper to obtain a gas stream comprising contaminants and a lean solvent that is recycled to the absorption column. BTX is often used as acronym for benzene, toluene, and xylenes (e.g. o-xylene, m-xylene and/or p-xylene). BTEX is often used as acronym for benzene, toluene, ethylbenzene, and xylenes (e.g. o-xylene, m-xylene and/or p-xylene).

When producing LNG (liquefied natural gas), BTEX is removed prior to liquefaction to avoid freezing. When the level of BTEX in the gas is too high, tubes may become plugged during liquefaction. Generally it is preferred to have a BTEX concentration in the gas of at most 3 ppmv (parts per million by volume) before liquefaction. W02007003618 describes a process in which benzene, toluene, o-xylene, m-xylene and p-xylene (BTX) are removed by means of an absorbing liquid comprising a physical solvent. In this step hydrogen sulfide and carbon dioxide are also removed to a large extent. In a preferred process a mixture of sulfolane, a secondary or tertiary amine, and water is used as absorbing liquid.

After benzene, toluene, and xylenes have been removed to a large extend by means of an absorbing liquid, it is necessary to lower the their concentration further. This is typically performed by means of a scrubber column, an adsorber, an extraction unit, or another type of BTEX or BTX removal unit. In such a second step it is sometimes also possible to remove hydrocarbons with more than 5 carbon atoms (C5+) from the gas.

There is a need for an improved process in which the removal of benzene, toluene, and xylenes is more efficient, without disturbing the removal of hydrogen sulfide and carbon dioxide.

Summary of the invention

It has now been found that the efficiency of the removal of benzene, toluene, and xylenes can be increased by contacting the gas with a specific absorption liquid and reducing the temperature in the absorption column.

Accordingly, the invention relates to a process wherein a purified gas stream is produced from a feed gas stream comprising natural gas, carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene. The process comprises the following steps: (a) contacting the feed gas stream with absorbing liquid comprising sulfolane and a secondary or tertiary amine in an absorption column, and reducing the temperature of the absorbing liquid at an intermediate section of the absorption column, to obtain loaded absorbing liquid comprising carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, o-xylene, m-xylene and p-xylene, and a gas stream depleted of these compounds; (b) cooling and de-pressurizing at least a part of the gas stream obtained in step (a) to obtain a liquid comprising aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene, and flash gas depleted of these compounds.

An advantage of the process according to the invention is that the efficiency of the removal of benzene, toluene, and xylenes (BTX) has been increased in step (a).

Step (b) has as additional advantage that the efficiency of the removal of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene (BTEX) is improved.

Another advantage is that NGL and aromatics can be removed by the cooling and de-pressurization of step (b).

Step (b) can be performed in one or more single stage flash vessels. There is no need to use a scrubbing column, a deethanizer or de-methanizer, an adsorber, or an extraction unit. Apart from one or more single stage flash vessels, there is no need to use another BTX or BTEX removal unit in step (b). And the NGL removal unit of an LNG plant can be significantly simplified. NGL stands for Natural Gas liquids, which are associated hydrocarbons such as C2H6, C3H8, nC4H10, and pentanes. A further advantage is that in step (b) flash gas comprising less than 3 ppmv BTEX can be obtained. This flash gas can be subjected to liquefaction to obtain LNG. Detailed description of the invention

In the process according to the invention, a purified gas stream is produced from a feed gas stream comprising natural gas, carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene. The process comprises the following steps: (a) contacting the feed gas stream with absorbing liquid comprising sulfolane and a secondary or tertiary amine in an absorption column, and reducing the temperature of the absorbing liquid at an intermediate section of the absorption column, to obtain loaded absorbing liquid comprising carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, o-xylene, m-xylene and p-xylene, and a gas stream depleted of these compounds; (b) cooling and de-pressurizing at least a part of the gas stream obtained in step (a) to obtain a liquid comprising aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene, and flash gas depleted of these compounds.

The feed gas stream comprises natural gas, carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene. The feed gas stream may also comprise hydrocarbons with more than 5 carbon atoms (C5+).

Natural gas is a general term that is applied to mixtures of light hydrocarbons and optionally other gases (nitrogen, carbon dioxide, helium) derived from natural gas wells. The main component of natural gas is methane.

Further, often ethane, propane and butane are present. In some cases (small) amounts of higher hydrocarbons may be present, often indicated as natural gas liquids or condensates. When produced together with oil, the natural gas is usually called associated gas. Other compounds that may be present as contaminants in natural gas in varying amounts include carbon dioxide, hydrogen sulphide, and aromatic compounds.

The feed gas stream may comprise H2S, for example in the range of from 1 ppmv to 10 vol%, based on the total feed gas stream. The feed gas stream may also comprise carbon dioxide, for example in the range of from 0 to 40 vol%, based on the total feed gas stream.

In case the feed gas stream additionally comprises hydrocarbons with more than 5 carbon atoms, the loaded absorbing liquid obtained in step (a) also additionally comprises hydrocarbons with more than 5 carbon atoms and the liquid obtained in step (b) additionally comprises hydrocarbons with more than 5 carbon atoms.

Preferably the absorbing liquid is used in step (a) to remove contaminants by transferring contaminants from the feed gas stream to the absorbing liquid. This results in an absorbing liquid loaded with contaminants. The loaded absorbing liquid may be regenerated by contacting with a regeneration gas.

The absorbing liquid comprises sulfolane and a secondary or tertiary amine. Sulfolane is a physical solvent. The secondary or tertiary amine is a chemical solvent. Preferably the absorbing liquid additionally comprises another solvent, most preferably water.

Preferably the amount of sulfolane is in the range of from 10 to 80, more preferably from 15 to 50, still more preferably from 20 to 35 parts by weight, based on the total absorbing liquid. The remainder of the absorbing liquid is secondary or tertiary amine and suitably another solvent, preferably water.

Examples of suitable secondary or tertiary amines are an amine compound derived from ethanol amine, more especially DIPA (di-isopropanolamine), DEA, MMEA (monomethyl-ethanolamine), MDEA, or DEMEA (diethyl-monoethanolamine), preferably DIPA or MDEA, most preferably DIPA.

The absorbing liquid may further comprise a so-called activator compound. Suitable activator compounds are piperazine, methyl-ethanolamine, or (2-aminoethyl)-ethanolamine, especially piperazine. A preferred absorbing liquid comprises sulfolane, MDEA and piperazine.

For the current process a highly preferred absorbing liquid comprises sulfolane, water and DIPA.

The absorbing liquid typically comprises water, preferably in the range of from 15 to 45 parts by weight, more preferably of from 15 to 40 parts by weight of water.

In step (a) the temperature of the absorbing liquid is reduced at an intermediate section of the absorption column. Preferably the temperature of the absorbing liquid is reduced by means of removing absorbing liquid from the absorption column, cooling the removed absorbing liquid, and feeding cooled absorbing liquid back to the absorbing column .

Most preferably cooled liquid is fed back to the absorbing column at a level lower than at which absorbing liquid to be cooled is removed from the absorbing column.

But it can also be fed back at the same level, or at a level higher than at which absorbing liquid to be cooled is removed from the absorbing column.

In a preferred embodiment the temperature of the absorbing liquid is reduced by means of inter-stage cooling. The temperature of the absorbing liquid may be reduced by means of an intercooler. An intercooler can be obtained, for example, from Black & Veatch. An example of an absorption column with inter-stage cooling is provided in Figure 1.

In step (b) gas obtained in step (a) preferably is cooled to a temperature in the range of between -30 and -100 °C, preferably between -35 and -100 °C, more preferably between -35 and -70 °C, even more preferably between -35 and -65 °C, before de-pressurizing.

Preferably depressurization in step (b) is performed in one or more single stage flash vessels. Step (b) may be performed with a simple knock out vessel. Suitable flash vessels can be obtained, for example, from Linde Star LNG.

After step (b) it is not necessary to use a scrubbing column, a de-ethanizer or de-methanizer, an adsorber, or an extraction unit.

The flash gas obtained in step (b) may be (partially) subjected to liquefaction.

According to an embodiment, the flash gas obtained in step (b) comprises less than 3 ppmv BTEX and is passed to a liquefaction unit, in particular to one or more heat exchangers comprised by the liquefaction unit, without being passed through any further BTEX removal equipment and/or hydrocarbon extraction/separation unit (NGL extraction), in particular without being passed through a scrubbing column, a de-ethanizer or de-methanizer, an adsorber and an extraction unit.

Passing the flash gas to the liquefaction unit, in particular to one or more heat exchangers comprised by the liquefaction unit, may comprise passing the flash gas through a water removal unit and/or a mercury removal unit.

The liquefaction unit may comprise a pre-cooling heat exchanger and a main cryogenic heat exchanger. Both the pre-cooling heat exchanger and/or the main cryogenic heat exchanger may be formed by one or more parallel and/or serial sub-heat exchangers.

The liquefaction unit may use a C3-MR process in which the refrigerant used for the pre-cooling heat exchanger is mainly propane and the refrigerant used for the main cryogenic heat exchanger is a mixed refrigerant. The liquefaction unit may use a DMR process in which the refrigerant used for the pre-cooling heat exchanger is a first mixed refrigerant and the refrigerant used for the main cryogenic heat exchanger is a second mixed refrigerant.

Optionally a part of the flash gas obtained in step (b) is recycled to the absorption column. When a part of the flash gas is recycled to step (a), the feed gas stream and the flash gas are contacted with the absorbing liquid in the absorption column.

Figure 1

Figure 1 shows an example of an absorption column with inter-stage cooling. A feed gas stream enters the absorption column via line 1. A gas stream depleted of carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, o-xylene, m-xylene and p-xylene leaves the absorption column via line 2. This gas is subjected to step (b), and optionally additionally to liquefaction.

Absorbing liquid, which may be regenerated absorbing liquid, enters the absorption column via line 3. The absorbing liquid entering via line 3 does not comprise or is lean with regard to carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, o-xylene, m-xylene and p-xylene.

The absorption of carbon dioxide is exothermal and the temperature of the absorbing liquid increases while flowing down the column. The temperature of the absorbing liquid is at an intermediate section of the absorption column. Warm absorbing liquid is removed from the absorption column via line 5 and after cooling fed back to the absorption column via line 6.

Examples

Experiments according to the present invention were performed with a feed gas stream comprising natural gas, carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene. The feed gas stream was contacted with absorbing liquid comprising sulfolane and a secondary or tertiary amine in an absorption column.

In Experiment 1 the amine was MDEA, and the absorption liquid also comprised piperazine. Step (b) of the current process was not performed. The table below shows that the absorption liquid comprising water, sulfolane, MDEA and piperazine results in very good BTX removal.

In Experiment 2 the amine was DIPA. Step (b) of the current process was not performed. The table below shows that the absorption liquid comprising water, sulfolane and DIPA results in excellent BTX removal.

In Experiment 3 the amine was DIPA. Step (b) of the current process was performed. The table below shows that the absorption liquid comprising water, sulfolane and DIPA results in an even better BTX removal than Experiment 2.

For step (b) the influence of the cooling temperature before de-pressurizing was investigated. The BTX removal of step (b) increases when the gas is cooled deeper.

The person skilled in the art will readily understand that many modifications may be made without departing from the scope of the invention. For instance, it is noted here that step (b) is an optional step. Furthermore, where the word step or steps is used in this text, it will be understood that this is not done to imply a specific order. The steps may be applied in any suitable order, including simultaneously.

Claims

1. A process for producing a purified gas stream from a feed gas stream comprising natural gas, carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene, the process comprising the following steps: (a) contacting the feed gas stream with absorbing liquid comprising sulfolane and a secondary or tertiary amine in an absorption column, and reducing the temperature of the absorbing liquid at an intermediate section of the absorption column, to obtain loaded absorbing liquid comprising carbon dioxide, hydrogen sulphide, and aromatic compounds selected from the group of benzene, toluene, o-xylene, m-xylene and p-xylene, and a gas stream depleted of these compounds; (b) cooling and de-pressurizing at least a part of the gas stream obtained in step (a) to obtain a liquid comprising aromatic compounds selected from the group of benzene, toluene, ethylbenzene, o-xylene, m-xylene and p-xylene, and flash gas depleted of these compounds.

2. The process according to claim 1, wherein the level at which absorbing liquid enters the absorption column and the level at which feed gas stream enters the absorption column are separated by a height H, and the temperature of the absorbing liquid is reduced at a level lower than 0.1 H from the level at which absorbing liquid enters the absorption column and higher than 0.1 H from the level at which feed gas stream enters the absorption column, preferably the temperature of the absorbing liquid is reduced at a level lower than 0.2 H from the level at which absorbing liquid enters the absorption column and higher than 0.2 H from the level at which feed gas stream enters the absorption column, more preferably the temperature of the absorbing liquid is reduced at a level lower than 0.3 H from the level at which absorbing liquid enters the absorption column and higher than 0.3 H from the level at which feed gas stream enters the absorption column.

3. The process according to any one of the preceding claims, wherein the temperature of the absorbing liquid is reduced by means of removing absorbing liquid from the absorption column, cooling the removed absorbing liquid, and feeding cooled absorbing liquid back to the absorbing column.

4. The process according to any one of the preceding claims, wherein the temperature of the absorbing liquid is reduced by means of inter-stage cooling.

5. The process according to any one of the preceding claims, wherein the temperature of the absorbing liquid is reduced by means of an intercooler.

6. The process according to any one of the preceding claims, wherein the feed gas stream additionally comprises hydrocarbons with more than 5 carbon atoms, and the loaded absorbing liquid obtained in step (a) additionally comprises hydrocarbons with more than 5 carbon atoms.

7. The process according to any one of the preceding claims wherein step (b) is performed, and wherein the feed gas stream additionally comprises hydrocarbons with more than 5 carbon atoms, and the loaded absorbing liquid obtained in step (a) additionally comprises hydrocarbons with more than 5 carbon atoms, and the liquid obtained in step (b) additionally comprises hydrocarbons with more than 5 carbon atoms .

8. The process according to any one of the preceding claims wherein in step (b) at least a part of the gas stream obtained in step (a) is cooled to a temperature in the range of between -30 and -100 °C, preferably between -35 and - 100 °C, more preferably between -35 and -70 °C, even more preferably between -35 and -65 °C, before de-pressurizing.

9. The process according to any one of the preceding claims wherein the depressurization in step (b) is performed in one or more single stage flash vessels.

10. The process according to any one of the preceding claims wherein no use is made of a scrubbing column, a deethanizer or de-methanizer, an adsorber, or an extraction unit.

11. The process according to any one of the preceding claims wherein the flash gas obtained in step (b) is subjected to liquefaction, and optionally a part of the flash gas obtained in step (b) is recycled to step (a).

12. The process according to any one of the preceding claims, wherein the flash gas obtained in step (b) comprises less than 3 ppmv BTEX and is passed to a liquefaction unit without being passed through any further BTEX removal equipment and/or hydrocarbon extraction/separation unit (NGL extraction), in particular without being passed through a scrubbing column, a deethanizer or de-methanizer, an adsorber and an extraction unit.