WO2018207726A1 - Hydrogen sulfide removal device and hydrogen sulfide removal method - Google Patents

Abstract

A hydrogen sulfide removal device 1 which is characterized by comprising: a hydrogen sulfide removal unit 30 which removes hydrogen sulfide by bringing a first starting material that contains hydrocarbon and hydrogen sulfide into contact with an oil-soluble hydrogen sulfide absorbent; and a mixing unit 40 which mixes a second starting material that contains a high-boiling-point hydrocarbon, which has a boiling point not lower than the boiling point of propane, with a hydrogen sulfide absorbed agent, which is the hydrogen sulfide absorbent that has absorbed the hydrogen sulfide. It is preferable that this hydrogen sulfide removal device 1 is additionally provided with a first separation unit 20, which separates the high-boiling-point hydrocarbon from the first starting material, in the preceding stage of the hydrogen sulfide removal unit 30.

Description

Hydrogen sulfide removing apparatus and hydrogen sulfide removing method

The present invention relates to a hydrogen sulfide removing device and a hydrogen sulfide removing method.
This application claims priority based on Japanese Patent Application No. 2017-095944 for which it applied to Japan on May 12, 2017, and uses the content here.

Oilfield associated gas and natural gas produced in the course of oil production include methane and other hydrocarbons, which are the main components, as well as moisture, nitrogen gas, carbon dioxide, hydrogen sulfide, etc. Is included). Among these, hydrogen sulfide causes corrosion of the pipeline in addition to its toxicity and odor, so that it is required to make the concentration as low as possible (for example, less than 20 ppm).

As a method of removing hydrogen sulfide contained in natural gas, a method of removing hydrogen sulfide by adsorbing it on an adsorbent, and a method of removing hydrogen sulfide by absorbing it in a liquid absorbent are known. Examples of the adsorbent include iron oxide and zinc oxide, and examples of the absorbent include an amine solution and a dialdehyde having aldehyde groups at both ends of a long-chain alkane as in Patent Document 1. Among these, the amine absorption method in which hydrogen sulfide is absorbed in an amine-based solution is widely adopted because it can simultaneously remove carbon dioxide.

International Publication No. 2015/141535

However, in the method for removing hydrogen sulfide using an adsorbent such as iron oxide, a large amount of waste is generated and the environmental load is large.
In addition, the amine absorption method requires a regeneration step for heating and regenerating the absorbing solution that has absorbed carbon dioxide and hydrogen sulfide, and also requires a process for separating and removing hydrogen sulfide generated in the regeneration step. For this reason, the scale of a plant becomes large and it cannot be profitable in terms of processing costs.
In Patent Document 1, no consideration is given to the treatment of an absorbent that absorbs hydrogen sulfide (also referred to as an absorbed agent).
For this reason, in the prior art, the treatment of the absorbed agent or the like is complicated, and hydrogen sulfide cannot be removed efficiently.

Therefore, an object of the present invention is to provide a hydrogen sulfide removal apparatus and a hydrogen sulfide removal method that can efficiently remove hydrogen sulfide contained in natural gas or the like.

The present invention has the following aspects.
[1] A hydrogen sulfide removing portion for removing the hydrogen sulfide by bringing the first raw material containing hydrocarbon and hydrogen sulfide into contact with an oil-soluble hydrogen sulfide absorbent, and high boiling carbonization having a boiling point higher than that of propane. A hydrogen sulfide removing apparatus comprising: a mixing unit that mixes a second raw material containing hydrogen and a hydrogen sulfide absorbed agent obtained by absorbing the hydrogen sulfide in the hydrogen sulfide absorbent.
[2] The hydrogen sulfide removing device according to [1], further comprising a first separation unit that separates the high-boiling hydrocarbons from the first raw material before the hydrogen sulfide removal unit. .
[3] The method further comprises a second separation unit for separating the high-boiling hydrocarbons from the first raw material treated in the hydrogen sulfide removal unit, after the hydrogen sulfide removal unit. [1] Or the hydrogen sulfide removal apparatus as described in [2].
[4] The method further comprises an introduction part that introduces the mixture of the high-boiling hydrocarbon obtained in the first separation part and the hydrogen sulfide absorbent into the hydrogen sulfide removal part. [2] The hydrogen sulfide removing apparatus according to 1.

Furthermore, this invention has the following aspects.
[5] A hydrogen sulfide removing step of removing the hydrogen sulfide by bringing the first raw material containing hydrocarbon and hydrogen sulfide into contact with an oil-soluble hydrogen sulfide absorbent, and high boiling carbonization having a boiling point higher than that of propane. A mixing step of mixing a second raw material containing hydrogen and a hydrogen sulfide absorbed agent obtained by absorbing the hydrogen sulfide in the hydrogen sulfide absorbent, and removing the hydrogen sulfide from the first raw material A method for removing hydrogen sulfide.
[6] The method for removing hydrogen sulfide according to [5], further comprising a first separation step for separating the high-boiling hydrocarbons from the first raw material before the hydrogen sulfide removal step. .
[7] The method further comprises a second separation step for separating the high-boiling hydrocarbons from the first raw material treated in the hydrogen sulfide removal step after the hydrogen sulfide removal step, [5] Or the hydrogen sulfide removal method as described in [6].
[8] A premixing step of mixing the high-boiling hydrocarbons obtained in the first separation step and the hydrogen sulfide absorbent, wherein the hydrogen sulfide removal step includes the first raw material and the premixing The method for removing hydrogen sulfide according to [6], wherein the mixture obtained in the step is contacted.
[9] In the mixing step, the second raw material and the hydrogen sulfide absorbed agent are mixed under a condition that the high boiling point hydrocarbon is in a pressurized liquefied state. [5] to [5] 8] The method for removing hydrogen sulfide according to any one of the above.
[10] The method for removing hydrogen sulfide according to any one of [5] to [8], wherein the high-boiling hydrocarbon is liquid at room temperature.

According to the hydrogen sulfide removing device and the hydrogen sulfide removing method of the present invention, hydrogen sulfide contained in natural gas or the like can be efficiently removed.

It is a systematic diagram which shows the structure of the hydrogen sulfide removal apparatus which concerns on 1st embodiment of this invention. It is a systematic diagram which shows the structure of the hydrogen sulfide removal apparatus which concerns on 2nd embodiment of this invention. It is a systematic diagram which shows the structure of the hydrogen sulfide removal apparatus which concerns on 3rd embodiment of this invention.

The hydrogen sulfide removing device of the present invention includes a hydrogen sulfide removing unit and a mixing unit.
The hydrogen sulfide removal apparatus of the present invention can be applied as, for example, a hydrocarbon purification apparatus (an apparatus for producing purified hydrocarbon). In particular, it is suitable as an apparatus for producing LNG (Liquid Natural Gas).
The method for removing hydrogen sulfide of the present invention includes a hydrogen sulfide removing step and a mixing step.
The hydrogen sulfide removal method of the present invention can be applied as, for example, a hydrocarbon purification method (a method for producing a purified hydrocarbon). In particular, it is suitable as an LNG manufacturing method.

[First embodiment]
Hereinafter, a hydrogen sulfide removing apparatus according to a first embodiment of the present invention and a hydrogen sulfide removing method using the apparatus will be described in detail with reference to the drawings.
The hydrogen sulfide removing apparatus of the present invention is an apparatus for removing hydrogen sulfide from a first raw material containing hydrocarbon (alkane) and hydrogen sulfide and taking out purified hydrocarbon as a target gas.
In addition, in the drawings used in the following description, in order to make the features easy to understand, there are cases where the portions that become the features are enlarged for the sake of convenience, and the dimensional ratios of the respective components are not always the same as the actual ones. Absent.

<Hydrogen sulfide removal device>
FIG. 1 is a system diagram showing the configuration of the hydrogen sulfide removing apparatus according to the first embodiment of the present invention. As shown in FIG. 1, the hydrogen sulfide removal apparatus 1 includes a separator 12, a first separation unit 20, a hydrogen sulfide removal unit 30, a mixing unit 40, an absorbent supply source 50, an LPG (Liquid Petroleum Gas). , Liquefied petroleum gas) tank 60 and pipes L1 to L8.

A separator 12 is provided in the subsequent stage of the raw material supply source 10, and the raw material supply source 10 and the separator 12 are connected by a pipe L1.
A first separation unit 20 is provided in the subsequent stage of the separator 12, and the separator 12 and the first separation unit 20 are connected by a pipe L1.
A hydrogen sulfide removing unit 30 and a mixing unit 40 are provided after the first separation unit 20. The first separation unit 20 and the hydrogen sulfide removal unit 30 are connected by a pipe L2. The first separation unit 20 and the mixing unit 40 are connected by a pipe L3. The pipe L3 is provided with a compressor 90. A pipe L5 is connected to the hydrogen sulfide removing unit 30. A mixing unit 40 is provided after the hydrogen sulfide removing unit 30, and the hydrogen sulfide removing unit 30 and the mixing unit 40 are connected by a pipe L4. The pipe L4 is provided with a branch 101 and a pump 71.
An LPG tank 60 is provided downstream of the mixing unit 40, and the mixing unit 40 and the LPG tank 60 are connected by a pipe L8. The pipe L6 branches from the branch 101 and is connected to the introduction unit 80 provided in the hydrogen sulfide removal unit 30. The pipe L6 includes a pump 70 and a branch 102. The pipe L7 branches from the branch 102 and is connected to the absorbent supply source 50.

(Raw material supply source)
The raw material supply source 10 is a supply source (supply unit) that supplies a first raw material containing hydrocarbons and hydrogen sulfide to the hydrogen sulfide removing device 1.
The first raw material only needs to contain hydrocarbons and hydrogen sulfide. For example, the extracted natural gas, the liquefied petroleum gas obtained when refining petroleum, the oil field associated gas produced by the oil production Examples thereof include coal bed methane (CBM) that can be collected from a coal bed, coke oven gas obtained when coal is carbonized in a coke oven, and the like. The first raw material may contain gas such as carbon dioxide, nitrogen, helium in addition to hydrocarbon and hydrogen sulfide.
The first raw material may be gas or liquid, may be a mixture of gas and liquid, or may be a mixture of gas, liquid and solid.

The raw material supply source 10 only needs to be able to supply the first raw material. The ground facility of the oil and gas field, a pipeline connected to the oil gas field, a tank capable of temporarily storing the first raw material, and a movable tank Examples include a loaded vehicle. The raw material supply source 10 can also be applied to an LNG plant, a biogas plant, or the like.

The pipe L1 may be a metal or resin pipe, but is not limited to these pipes. Further, the material of the pipe L1 may be the same as or different from the material of the other pipe L2. Hereinafter, the types and materials of the piping in this specification are the same.

(Separator)
The separator 12 is a device that removes moisture, sludge, and the like contained in the first raw material.
As the separator 12, a known device that removes moisture, sludge, and the like from natural gas, crude oil, or the like may be used. Examples of the separator 12 include an apparatus that removes moisture, sludge, and the like in the first raw material using a coalescer made of lipophilic fibers or the like, or a hydrophilic filter.
In the present embodiment, hydrocarbons having 5 or more carbon atoms are removed as sludge or the like by the separator 12, and hydrocarbons having 4 or less carbon atoms (methane, ethane, propane, butane) are supplied to the first separation unit 20. Etc. are supplied.

(First separation part)
The first separation unit 20 is an apparatus for separating high-boiling hydrocarbons having a boiling point equal to or higher than that of propane (hereinafter also simply referred to as “high-boiling hydrocarbons”) from the first raw material. Here, “boiling point of propane” means −42 ° C. The high boiling point hydrocarbons are propane and hydrocarbons (alkanes) having 4 or more carbon atoms, but the separator 12 is provided as described above to substantially remove hydrocarbons (alkanes) having 5 or more carbon atoms. It is preferable to do. That is, the high boiling point hydrocarbon is preferably mainly composed of propane or butane, or both.
In the first separation unit 20, the second raw material containing the high boiling point hydrocarbon is separated from the first raw material.
In the present embodiment, the first separation unit 20 separates the second raw material containing high-boiling hydrocarbons (propane, butane, etc.) from the first raw material.

The first separation unit 20 uses a separation membrane that can separate hydrocarbons according to differences in the molecular weight and size of the hydrocarbons.
In the present embodiment, the separation membrane refers to a permeable body having a structure having a difference in transmittance depending on the type of gas due to a fine through hole or the like and having gas permeability. Examples of the mechanism include a mechanism for controlling the transmittance according to the relationship between the size of the through hole and the molecule, and a mechanism for utilizing an average free process based on the molecular weight of the gas. Based on various mechanisms, there are various materials such as ceramics such as zeolite, polyimide, organic compounds such as cellulose, silicone, and fluorine-based polymers. Examples of the form of the separation apparatus using the separation membrane include forms provided as various separation membrane modules such as a cylindrical shape, a hollow fiber, a flat plate, or a bag-like separation membrane wound into a cylindrical shape. These separation membranes can be selected according to the price of natural gas that is the first raw material, the price of hydrocarbon gas such as methane that is the product gas, and the like.

The first separation unit 20 is not limited to a separation device using a separation membrane as long as the second raw material can be separated from the first raw material, and a known device for separating hydrocarbons is used. Also good. Examples of the first separation unit 20 include an atmospheric distillation apparatus such as a slag catcher, a topper, and a naphtha splitter.

(Hydrogen sulfide removal part)
The hydrogen sulfide removing unit 30 is an apparatus that removes hydrogen sulfide by bringing the first raw material into contact with an oil-soluble hydrogen sulfide absorbent (hereinafter also simply referred to as “absorbent”).
The hydrogen sulfide removing unit 30 is constituted by, for example, a reactor such as an absorption tower, and an introduction unit 80 for supplying an absorbent is provided inside the absorption tower.
The hydrogen sulfide removing unit 30 is a device that sprays the absorbent from the introduction unit 80 into the absorption tower and contacts the first raw material.
The hydrogen sulfide removing unit 30 is not limited to an apparatus that sprays the absorbent, and may be an apparatus that removes hydrogen sulfide by bubbling the first raw material into a liquid stored in the bottom of the absorption tower.

Examples of the oil-soluble hydrogen sulfide absorbent include dialdehydes having aldehyde groups in the vicinity of both ends of a long-chain alkane skeleton. Examples of the dialdehyde include 1,9-nonanedial, which has low toxicity, excellent heat resistance, and storage stability, and 2-methyl-1,8-octanedial (2- methyl-1,8-octanedial) and the like.
The absorbent is preferably used in the form of a solution. For example, as the absorbent, 1,9-nonane dial, 2-methyl-1,8-octane dial, etc. are 2 to 10 times (volume basis) kerosene, naphtha, low molecular weight polyethylene glycol (molecular weight 200 to 1000). Those dissolved in a solvent such as the above are preferably used. Here, kerosene means a fraction having a flash point of 40 ° C. or higher and a 95% by volume distillation temperature of 300 ° C. or lower. The flash point refers to a value measured according to JIS K2265. The naphtha is a fraction having a 10% by volume distillation temperature of 50 ° C. or more and a 90% by volume distillation temperature of 150 ° C. or less, and containing a fraction having a boiling point range of 30 to 150 ° C. means.
In this specification, “oil-soluble” refers to a compound that does not phase-separate when compound and kerosene are mixed in the range of 2: 8 to 8: 2 with No. 1 kerosene specified in JIS K2203: 2009. It shall mean the property possessed.

(Mixing part)
The mixing unit 40 is a device that mixes the second raw material containing the high-boiling point hydrocarbon and the hydrogen sulfide absorbed agent.
Examples of the mixing unit 40 include a batch type mixing device and an inline type mixing device.

(Absorbent source)
The absorbent supply source 50 is a supply source that supplies the hydrogen sulfide absorbent to the hydrogen sulfide removal unit 30.
The absorbent supply source 50 only needs to be able to supply the absorbent, and examples thereof include a built-in tank capable of temporarily storing the absorbent and a movable tank-loaded vehicle.

(LPG tank)
The LPG tank 60 is a tank for temporarily storing a mixture of the absorbed agent and the second raw material.
The LPG tank 60 only needs to be able to temporarily store the mixture of the absorbed agent and the second raw material, and examples thereof include a built-in tank that can temporarily store the mixture and a movable tank-loaded vehicle.

<Method of removing hydrogen sulfide>
Next, a method for removing hydrogen sulfide from the first raw material using the hydrogen sulfide removing apparatus 1 will be described.
The present embodiment includes a hydrogen sulfide removal step and a mixing step, and further includes a first separation step for separating high-boiling hydrocarbons from the first raw material before the hydrogen sulfide removal step.

The first raw material containing hydrocarbons and hydrogen sulfide is supplied from the raw material supply source 10 to the separator 12 via the pipe L1.
The hydrocarbon in the first raw material contains methane, ethane, and high-boiling hydrocarbons such as propane and butane having a boiling point higher than that of propane.
The first raw material contains moisture, sludge and the like in addition to hydrocarbons and hydrogen sulfide.
If moisture, sludge, or the like is contained in the first raw material, it is not possible to obtain a high-purity target gas or high-quality LPG. Therefore, it is preferable to remove impurities such as moisture and sludge in the first raw material.
By removing moisture, sludge and the like in the first raw material, it is possible to obtain target gas with high purity and high quality LPG.

Moisture, sludge, and the like are removed from the first raw material treated by the separator 12 and supplied to the first separation unit 20 via the pipe L1.
The first separation unit 20 separates the second raw material containing the high-boiling hydrocarbons from the first raw material (first separation step).
In this embodiment, high boiling point hydrocarbons are propane and butane, and are separated as a gas at room temperature.
In this specification, room temperature means 1 to 30 ° C.

The first raw material processed in the first separation unit 20 is supplied to the hydrogen sulfide removal unit 30 via the pipe L2. The high boiling point hydrocarbon is removed from the first raw material supplied to the hydrogen sulfide removing unit 30. Therefore, the hydrocarbons (alkanes) in the first raw material supplied to the hydrogen sulfide removing unit 30 are methane and ethane.
The separated second raw material is supplied to the mixing unit 40 via the pipe L3.
In the present embodiment, since the high boiling point hydrocarbon is separated as a gas at room temperature, the high boiling point hydrocarbon is compressed by the compressor 90 and moves in the pipe L3 as a liquid (LPG) at room temperature to be mixed. To the unit 40.

The absorbent is supplied from the absorbent supply source 50 to the introduction unit 80 through the pipe L7, the branch 102, and the pipe L6. The absorbent supplied to the introduction unit 80 is sprayed in an absorption tower in the hydrogen sulfide removal unit 30 and an absorption operation for absorbing hydrogen sulfide is performed (hydrogen sulfide removal step). The sprayed absorbent absorbs hydrogen sulfide and is recovered as a hydrogen sulfide absorbed agent (hereinafter also simply referred to as “absorbed agent”) at the bottom of the absorption tower, and part of the pressure is increased by the pump 70 from the branch 101. Circulate the pipe L6.
In the hydrogen sulfide removing unit 30, the hydrogen sulfide in the first raw material is transferred to the absorbent in the mixture by bringing the first raw material into contact with the mixture of the absorbent and the absorbed agent.
The hydrogen sulfide absorbed agent having absorbed hydrogen sulfide in the absorbent is pressurized by the pump 71 in the pipe L4 and then supplied to the mixing unit 40 through the pipe L4.

In the hydrogen sulfide removing unit 30, hydrogen sulfide is removed from the first raw material and sent to the pipe L5 as the target gas. The target gas is separated into an inert gas such as nitrogen or helium and LNG such as methane or ethane and shipped as a product in an LNG production process or the like as necessary.
The temperature in the hydrogen sulfide removing unit 30 in the hydrogen sulfide removing step is preferably −30 to 150 ° C., and more preferably 0 to 130 ° C. The pressure in the hydrogen sulfide removing section 30 in the hydrogen sulfide removing step is preferably −0.1 to 10 MPa, and more preferably 0 to 1.0 MPa.
The concentration of hydrogen sulfide contained in the target gas is preferably 100 ppm (volume basis) or less, more preferably 30 ppm or less, still more preferably 10 ppm or less, and particularly preferably 4 ppm or less. If the concentration of hydrogen sulfide in the target gas is 100 ppm or less, there is an advantage that the influence on the sense of smell can be suppressed even if it is exposed to the target gas leaked due to a leakage accident or the like. In addition, there is an advantage that the influence on airway irritation, conjunctivitis and the like can be suppressed, and when it is 4 ppm or less, there is an advantage that it can be shipped as a raw material gas for a gas pipeline in addition to the above advantages.
The concentration of hydrogen sulfide is most preferably 0 ppm, but if it is less than the above upper limit, the above-described advantages can be ensured, so that it is more than 0 ppm in consideration of economics when reducing to 0 ppm. There may be.

In the mixing unit 40, the second raw material supplied via the pipe L3 and the absorbed agent supplied via the pipe L4 are mixed (mixing step). Since the absorbent is oil-soluble, the absorbed agent that has absorbed hydrogen sulfide is also oil-soluble. For this reason, the absorbed agent and the high boiling point hydrocarbon in the second raw material have compatibility, and the absorbed agent and the second raw material can be mixed. At this time, both the absorbed agent and the second raw material are supplied to the mixing unit 40 as a liquid, so that the compatibility between them is further improved.
Therefore, in the mixing part 40, it is preferable to mix a 2nd raw material and an absorbed agent on the conditions from which a high boiling point hydrocarbon will be in a pressurized liquefaction state. Moreover, in the mixing part 40, it is preferable that the high boiling point hydrocarbon is liquid at room temperature. The mixing unit 40 may include a stirrer for better mixing the second raw material and the absorbed agent.
In the mixing unit 40, the absorbed agent mixed with the second raw material is an impurity of the second raw material. For this reason, the mass of the absorbed agent mixed with the second raw material is preferably 10% by mass or less, more preferably 1% by mass or less with respect to 100% by mass of the second raw material, and an existing LPG facility is used. In that case, 0.1% by mass or less is more preferable.
When kerosene or naphtha is used as the solvent of the absorbent, the vapor pressure of the second raw material can be lowered by setting the solvent of the absorbed agent to 100% by mass or more with respect to 100% by mass of the second raw material. it can. When the vapor pressure of the second raw material is lowered, the compressor 90, the pipe L3, the pipe L8, the LPG tank 60, etc. can be simplified. For this reason, the mass of the solvent of the absorbed agent is preferably 100% by mass or more with respect to 100% by mass of the second raw material.

The mixture of the absorbed agent and the second raw material mixed in the mixing unit 40 is supplied to the LPG tank 60 via the pipe L8.
In the present embodiment, since the hydrocarbon having 5 or more carbon atoms is removed from the first raw material by the separator 12, the high boiling point hydrocarbon in the second raw material is propane, butane, or both. For this reason, the mixture of the absorbed agent and the second raw material mixed in the mixing unit 40 is supplied to the mixing unit 40 as LPG whose main component is propane, butane, or the like.
Since the absorbed agent containing hydrogen sulfide is diluted with a large amount of LPG, the hydrogen sulfide-containing concentration in the mixture of the absorbed agent and the second raw material can be reduced. The hydrogen sulfide-containing concentration in the mixture of the absorbed agent and the second raw material is preferably 50 to 100 ppm by mass, and more preferably 50 to 70 ppm by mass. If the hydrogen sulfide content concentration in the mixture of the absorbed agent and the second raw material is 100 ppm by mass or less, it conforms to the LPG shipping standard, so it is shipped as an LPG product without going through the process of removing hydrogen sulfide again. It becomes possible. When the hydrogen sulfide-containing concentration in the mixture of the absorbed agent and the second raw material is 50 ppm by mass or more, the effect according to the present invention is more easily obtained.

The mixture of the absorbed agent and the second raw material can be temporarily stored in the LPG tank 60 and then carried out to the outside by means such as a tank lorry.
The mixture of the absorbed agent and the second raw material carried out may be mixed with separately produced crude oil and processed in a hydrodesulfurization facility of an existing petroleum refining facility. The hydrogen sulfide absorbed in the absorbed agent can be separated in a hydrodesulfurization facility and commercialized as simple sulfur in a sulfur recovery device of another facility.

In the present embodiment, since the hydrogen sulfide-containing concentration in the target gas can be lowered, the hydrogen sulfide removing device of the present embodiment is suitable as an LNG manufacturing device.

[Second Embodiment]
Next, a hydrogen sulfide removing device according to a second embodiment of the present invention and a hydrogen sulfide removing method using this device will be described. Hereinafter, FIG. 2 will be described focusing on the differences from the first embodiment described above. FIG. 2 is a system diagram showing the configuration of the hydrogen sulfide removing apparatus according to the second embodiment of the present invention. As shown in FIG. 2, the hydrogen sulfide removing device 2 includes a separator 12, a heavy metal removing unit 14, a first hydrogen sulfide removing unit 32, a second hydrogen sulfide removing unit 34, and an absorbent supply source 52. The second separation unit 22, the mixing unit 42, the LPG tank 60, the pipes L1 ′ to L8 ′, and the pipes L9 to 11 are schematically configured.

A separator 12 is provided in the subsequent stage of the raw material supply source 10, and the raw material supply source 10 and the separator 12 are connected by a pipe L1 ′.
A heavy metal removing unit 14 is provided at the subsequent stage of the separator 12, and the separator 12 and the heavy metal removing unit 14 are connected by a pipe L1 ′. A first hydrogen sulfide removing unit 32 is provided downstream of the heavy metal removing unit 14, and the heavy metal removing unit 14 and the first hydrogen sulfide removing unit 32 are connected by a pipe L1 ′.
A second hydrogen sulfide removing unit 34 and a mixing unit 42 are provided following the first hydrogen sulfide removing unit 32. The first hydrogen sulfide removing unit 32 and the second hydrogen sulfide removing unit 34 are connected by a pipe L2 ′. The first hydrogen sulfide removing unit 32 and the mixing unit 42 are connected by a pipe L3 ′. The pipe L3 ′ is provided with a pump 74.
A second separation unit 22 is provided downstream of the second hydrogen sulfide removal unit 34, and the second hydrogen sulfide removal unit 34 and the second separation unit 22 are connected by a pipe L5 ′. A mixing unit 42 is provided at the subsequent stage of the second separation unit 22, and the second separation unit 22 and the mixing unit 42 are connected by a pipe L <b> 10. The pipe L10 is provided with a compressor 92. A pipe L11 is connected to the second separation part 22.
The pipe L9 branches from the branch 103 provided in the pipe L3 ′, and is connected to the introduction part 82 provided in the first hydrogen sulfide removing part 32. The pipe L9 is provided with a pump 72 and a branch 104.
The pipe L4 ′ branches from the branch 104 of the pipe L9 and is connected to the second hydrogen sulfide removing unit 34. A branch 105 is provided in the pipe L4 ′.
The pipe L6 ′ branches from the branch 105 of the pipe L4 ′ and is connected to an introduction part 84 provided in the second hydrogen sulfide removal part 34. The pipe L6 ′ is provided with a pump 73 and a branch 106.
The pipe L7 ′ branches from the branch 106 of the pipe L6 ′ and is connected to the absorbent supply source 52.
An LPG tank 60 is provided at the subsequent stage of the mixing unit 42, and the mixing unit 42 and the LPG tank 60 are connected by a pipe L8 ′.

(Heavy metal removal part)
The heavy metal removing unit 14 is an apparatus for removing heavy metal components such as mercury vapor from the first raw material.
The heavy metal removing unit 14 is not particularly limited, and a known apparatus for removing heavy metals can be used. Examples of the heavy metal removing unit 14 include an adsorbent in which a metal sulfide is supported on silica gel, alumina or the like, or a mercury removing apparatus in which an adsorbent in which activated carbon is supported on a metal sulfide is filled.

(First hydrogen sulfide removal part)
The first hydrogen sulfide removing unit 32 is an apparatus that removes hydrogen sulfide by bringing the first raw material into contact with an oil-soluble hydrogen sulfide absorbent, similarly to the hydrogen sulfide removing unit 30 in the first embodiment described above. .

(Second hydrogen sulfide removal part)
The second hydrogen sulfide removing unit 34 is an apparatus that removes hydrogen sulfide by bringing the first raw material into contact with an oil-soluble hydrogen sulfide absorbent, like the hydrogen sulfide removing unit 30 in the first embodiment described above. .

In the present embodiment, the first separation unit 20 in the first embodiment described above is not provided in the preceding stage of the first hydrogen sulfide removal unit 32. Therefore, the first raw material supplied to the first hydrogen sulfide removing unit 32 includes high boiling point hydrocarbons. In the first hydrogen sulfide removing unit 32, a part of the high boiling point hydrocarbon is absorbed by the absorbent together with the hydrogen sulfide. For this reason, the 1st hydrogen sulfide removal part 32 has a function as a 1st separation part which isolate | separates a high boiling point hydrocarbon from a 1st raw material. The same applies to the second hydrogen sulfide removing unit 34.
The first hydrogen sulfide removing unit 32 and the second hydrogen sulfide removing unit 34 may be the same as or different from each other.

(Second separation part)
The second separation unit 22 is an apparatus for separating high-boiling hydrocarbons having a boiling point equal to or higher than that of propane from the first raw material, like the first separation unit 20 in the first embodiment described above.
The second separation unit 22 may be the same as or different from the first separation unit 20 in the first embodiment described above.

(Mixing part)
The mixing unit 42 is a device that mixes the second raw material containing the high-boiling hydrocarbons and the hydrogen sulfide absorbed agent, like the mixing unit 40 in the first embodiment described above.
Examples of the mixing unit 42 include a batch type mixing device and an inline type mixing device.
The mixing unit 42 may be the same as or different from the mixing unit 40.

The absorbent supply source 52 may be the same as or different from the absorbent supply source 50 in the first embodiment described above.
The pumps 72 to 74 may be the same as or different from the pumps 70 to 71 in the first embodiment described above.
The compressor 92 may be the same as or different from the compressor 90 in the first embodiment described above.

Next, a method for removing hydrogen sulfide from the first raw material using the hydrogen sulfide removing device 2 will be described.
The present embodiment includes a hydrogen sulfide removing step and a mixing step, and a second step of separating high boiling point hydrocarbons from the first raw material treated in the hydrogen sulfide removing step after the hydrogen sulfide removing step. It further has a separation step.

In the first raw material, moisture, sludge and the like are removed by the separator 12, and then heavy metal such as mercury vapor is removed by the heavy metal removing unit 14. The first raw material from which heavy metals such as moisture and sludge have been removed is supplied to the first hydrogen sulfide removing unit 32 via the pipe L1 ′.
The absorbent is supplied from the absorbent supply source 52 to the introduction part 82 through the pipe L7 ′, the branch 106, and the pipe L6 ′. The absorbent supplied to the introduction unit 82 is sprayed in an absorption tower in the second hydrogen sulfide removal unit 34, and an absorption operation for absorbing hydrogen sulfide is performed (hydrogen sulfide removal step).
The sprayed absorbent absorbs hydrogen sulfide and is recovered as an absorbed agent at the bottom of the absorption tower, and a part of the pressure is increased by the pump 73 from the branch 105 and circulates through the pipe L6 ′. The absorbed agent overflowed from the pipe L6 ′ is supplied to the introduction part 84 via the pipe L4 ′, the branch 104, and the pipe L9. The absorbed agent supplied to the introduction unit 84 is sprayed in an absorption tower in the first hydrogen sulfide removal unit 32, and an absorption operation for absorbing hydrogen sulfide is performed. The sprayed absorbed agent further absorbs hydrogen sulfide and is recovered at the bottom of the absorption tower, and a part thereof is pressurized by the pump 72 from the branch 103 and circulates through the pipe L9.
Further, the absorbed agent that has absorbed hydrogen sulfide is pressurized by the pump 74 in the pipe L3 ′, and is supplied to the mixing section 42 as a liquid at room temperature via the pipe L3 ′.

On the other hand, the first raw material from which part of the hydrogen sulfide and the high-boiling hydrocarbons has been removed by the first hydrogen sulfide removing unit 32 is supplied to the second hydrogen sulfide removing unit 34 through the pipe L2 ′. .
The first raw material from which hydrogen sulfide and a part of the high-boiling hydrocarbons are further removed by the second hydrogen sulfide removing unit 34 is supplied to the second separation unit 22 via the pipe L5 ′.
In the second separation unit 22, hydrogen sulfide is removed from the supplied first raw material (second separation step). Therefore, the gas from which the high-boiling point hydrocarbons are separated by the second separation unit 22 can be carried out to the outside as the target gas via the pipe L11.

On the other hand, the second raw material containing high-boiling hydrocarbons is compressed by the compressor 92 and supplied as a liquid at room temperature to the mixing unit 42 via the pipe L10.
In the mixing unit 42, the absorbed agent supplied from the pipe L3 ′ and the second raw material supplied from the pipe L10 are mixed (mixing step). The mixture of the absorbed agent and the second raw material mixed in the mixing unit 42 is supplied to the LPG tank 60 through the pipe L8 ′ as a liquid containing hydrogen sulfide.

In the present embodiment, the absorbed agent mixed with LPG can easily remove the LPG component by reducing the pressure. The absorbed agent from which the LPG component has been removed can be regenerated by a regeneration process as necessary to form an absorbent. The hydrogen sulfide removed by the regeneration process can be treated with existing hydrogen sulfide treatment equipment. In this case, the absorbent solvent (diluting solvent) is preferably kerosene, toluene or the like.
This embodiment is particularly effective in the case of a small scale and a small amount of LPG component (for example, less than 1% by volume), and is efficient in that a large-scale facility such as a slag catcher is not required.
In addition, since the LPG component can be absorbed and transported by the absorbent, the equipment can be simplified.

[Third embodiment]
Next, a hydrogen sulfide removing device according to a third embodiment of the present invention and a hydrogen sulfide removing method using this device will be described. Hereinafter, FIG. 3 will be described with a focus on differences from the first embodiment and the second embodiment described above. FIG. 3 is a system diagram showing the configuration of the hydrogen sulfide removing apparatus according to the third embodiment of the present invention. As shown in FIG. 3, the hydrogen sulfide removing device 3 includes an absorbent supply source 54, a first separation unit 24, a hydrogen sulfide removal unit 36, a heavy metal removal unit 14, a moisture removal unit 16, and a second The separation section 26, the mixing section 44, and the pipes L12 to L24 are schematically configured.

A first separation unit 24 is provided downstream of the raw material supply source 10, and the raw material supply source 10 and the first separation unit 24 are connected by a pipe L12. A hydrogen sulfide removing unit 36 is provided at the subsequent stage of the first separating unit 24, and the first separating unit 24 and the hydrogen sulfide removing unit 36 are connected by a pipe L13. A pipe L14 is connected to the subsequent stage of the first separation unit 24.
A pipe L15 is connected to the subsequent stage of the raw material supply source 18, and is connected to a branch 109 provided in the pipe L17. The pipe L15 joins the pipe L14 at the branch 107, joins the pipe L16 at the branch 108, and joins the pipe L17 at the branch 109.
A pipe L16 is connected to the subsequent stage of the absorbent supply source 54 and merges with the pipe L15 at the branch 108.
A heavy metal removing unit 14 and a mixing unit 44 are provided following the hydrogen sulfide removing unit 36. The hydrogen sulfide removing unit 36 and the heavy metal removing unit 14 are connected by a pipe L18. The hydrogen sulfide removing unit 36 and the mixing unit 44 are connected by a pipe L19. A branch 110 is provided in the pipe L19. The pipe L17 branches off at the branch 110 and is connected to an introduction part 86 provided in the hydrogen sulfide removal part 36. The pipe L17 is provided with a pump 75.
A water removal unit 16 is provided at the subsequent stage of the heavy metal removal unit 14, and the heavy metal removal unit 14 and the water removal unit 16 are connected by a pipe L18. A second separation unit 26 is provided at the subsequent stage of the moisture removal unit 16, and the moisture removal unit 16 and the second separation unit 26 are connected by a pipe L18. Pipes L20 to L22 are connected to the second separation unit.
A mixing unit 44 is provided in the subsequent stage of the second separation unit 26, and the second separation unit 26 and the mixing unit 44 are connected by a pipe L23.
A pipe L24 is connected to the subsequent stage of the mixing unit 44.

(Moisture removal part)
The moisture removing unit 16 is a device that removes moisture such as water vapor from the first raw material.
As the moisture removing unit 16, a known device that removes moisture from natural gas, crude oil, or the like may be used. Examples of the moisture removing unit 16 include an apparatus that removes moisture in the first raw material using a hydrophilic filter.

The second separation unit 26 is an apparatus for separating high-boiling hydrocarbons having a boiling point equal to or higher than that of propane from the first raw material, like the first separation unit 20 in the first embodiment described above.
The second separator 26 may be the same as or different from the first separator 20 in the first embodiment described above.

The hydrogen sulfide removing unit 36 is an apparatus that removes hydrogen sulfide by bringing the first raw material into contact with an oil-soluble hydrogen sulfide absorbent, like the hydrogen sulfide removing unit 30 in the first embodiment described above.
The hydrogen sulfide removing unit 36 may be the same as or different from the hydrogen sulfide removing unit 30 in the first embodiment described above.

The mixing unit 44 is an apparatus that mixes the second raw material containing the high-boiling hydrocarbons and the hydrogen sulfide absorbed agent, like the mixing unit 40 in the first embodiment described above.
Examples of the mixing unit 44 include a batch type mixing device and an inline type mixing device.
The mixing unit 44 may be the same as or different from the mixing unit 40.

The raw material supply source 18 may be the same as or different from the raw material supply source 10 in the first embodiment described above.
The absorbent supply source 54 may be the same as or different from the absorbent supply source 50 in the first embodiment described above.
The pump 75 may be the same as or different from the pumps 70 to 71 in the first embodiment described above.

Next, a method for removing hydrogen sulfide from the first raw material using the hydrogen sulfide removing device 3 will be described.
This embodiment is a preferred embodiment when the high-boiling hydrocarbons in the first raw material are relatively large.
The present embodiment includes a first mixing step, a hydrogen sulfide removing step, and a mixing step, and a premixing step of mixing the high boiling point hydrocarbon obtained in the first separation step and the hydrogen sulfide absorbent. Also have. In the hydrogen sulfide removing step, the first raw material is brought into contact with the mixture obtained in the premixing step.

The first raw material is supplied from the raw material supply source 10 to the first separation unit 24 via the pipe L12. In the first separation unit 24, the second raw material containing high-boiling hydrocarbons is separated from the first raw material (first separation step). The first separation unit 24 may be the same as or different from the separation unit described above. In this embodiment, the 1st separation part 24 serves as a separator and a slag catcher. The second raw material separated by the first separation unit 24 is so-called condensate oil containing an alkane having 3 to 4 carbon atoms and mainly having an alkane having 5 to 10 carbon atoms. Condensate oil is a liquid hydrocarbon at normal temperature and pressure obtained during the extraction and refining of natural gas from a natural gas field. It is extremely light and naphtha compared to ordinary crude oil obtained from oil fields. Close properties. The condensate oil merges with naphtha, kerosene, and the like supplied from the raw material supply source 18 at the branch 107 provided in the pipe L15 via the pipe L14.

The absorbent is supplied from the absorbent supply source 54 to the branch 108 via the pipe L16, and merges with a mixture of condensate oil, naphtha, kerosene, and the like. In the branch 108, the condensate oil, naphtha, kerosene, and the like and the absorbent are mixed (preliminary mixing step), and these mixtures are supplied to the branch 109 provided in the pipe L17 via the pipe L15. The mixture in the pipe L17 is supplied to the introduction unit 86 by the pump 75. The mixture of the absorbent and the high-boiling hydrocarbons supplied to the introduction unit 86 is sprayed in an absorption tower in the hydrogen sulfide removal unit 36, and an absorption operation for absorbing hydrogen sulfide is performed (hydrogen sulfide removal step). The sprayed mixture of the absorbent and the high boiling point hydrocarbon is recovered as an absorbed agent at the bottom of the absorption tower, and a part of the mixture is pressurized by the pump 75 from the branch 110 and circulates through the pipe L17.

In this embodiment, the introduction unit 86 introduces a mixture of condensate oil, high-boiling hydrocarbons such as naphtha and kerosene, and an absorbent into the hydrogen sulfide removal unit 36. The introduction part 86 of the present embodiment is different from the introduction part 80 and the second embodiment in the first embodiment in that the absorbent introduced into the hydrogen sulfide removal part 36 is already mixed with the high boiling point hydrocarbon. The introduction portion 82 and the introduction portion 84 in FIG.

The mixture of the absorbent that has absorbed hydrogen sulfide and the high boiling point hydrocarbon is supplied to the mixing section 44 through the pipe L19 as a liquid absorbed agent.
In the present embodiment, the absorbed agent moves as a liquid at room temperature in the pipe L19, so that a compressor is not necessary in the pipe L19.

On the other hand, the first raw material from which hydrogen sulfide has been removed is supplied to the second separation unit 26 via the pipe L18. From the first raw material, heavy metals such as mercury vapor are removed by the heavy metal removing unit 14, and then moisture such as water vapor is removed by the moisture removing unit 16. The first raw material from which the heavy metal and moisture are removed is supplied to the second separation unit 26 via the pipe L18.

In the second separation unit 26, the first raw material from which hydrogen sulfide, heavy metal components, and moisture have been removed is separated into an inert gas component such as carbon dioxide, an LNG component, an LPG component, and a condensate oil component. The The separated inert gas component is discharged to the outside through the pipe L20, and the LNG component is shipped as a product through the pipe L21. The separated LPG component is shipped as a product via the pipe L22, and the condensate oil component is supplied to the mixing unit 44 via the pipe L23.
In the mixing unit 44, the absorbed agent and the condensate oil component are mixed (mixing step) and supplied to an external oil refining facility or the like via the pipe L24.

In the present embodiment, since the absorbed agent that has absorbed hydrogen sulfide is liquid even at room temperature, there is an advantage that a pressure-resistant container is not required even at room temperature when transporting the absorbed agent.
Further, in the present embodiment, it is possible to replace with liquefaction processing such as GTL (Gas to Liquids) instead of natural gas LNG.

The LPG of this embodiment contains hydrogen sulfide, but by mixing the second raw material and the absorbed agent, the concentration of hydrogen sulfide is reduced, and the LPG can be shipped as a product.
In addition, when storing and transporting in a pressure vessel such as LPG, a small amount of hydrogen sulfide released from the absorbed agent can be used as an odorant, and gas leaks can be checked during storage and transportation of semi-finished products. Has the advantage of

As described above, according to the hydrogen sulfide removing device of the present invention, hydrogen sulfide can be efficiently removed from the first raw material. As a result, high quality LNG can be obtained. In addition, since the hydrogen sulfide removal device of the present invention uses an oil-soluble hydrogen sulfide absorbent, the absorbed agent that has absorbed hydrogen sulfide is also oil-soluble, and the absorbed agent is mixed with high-boiling hydrocarbons. As a result, LPG can be obtained.
Further, according to the hydrogen sulfide removing apparatus of the present invention, not only hydrogen sulfide but also mercaptans having an S—H (thiol) bond (generically referred to as hydrogen sulfide) can be removed.

As mentioned above, although embodiment of this invention was explained in full detail with reference to drawings, the concrete structure is not restricted to this embodiment, The design etc. of the range which does not deviate from the summary of this invention are included.
For example, the hydrogen sulfide removing device 2 described above has two hydrogen sulfide removing units, but the number of hydrogen sulfide removing units may be three or four or more. When the number of hydrogen sulfide removal units increases, the scale of the plant increases, but the concentration of hydrogen sulfide contained in the first raw material can be further reduced.
Moreover, although this embodiment has demonstrated the case where LPG is obtained as a high boiling point hydrocarbon, it is good also as a form which mixes LPG and crude oil, obtains crude oil, and ships crude oil.

By using the hydrogen sulfide removing apparatus and the hydrogen sulfide removing method of the present invention, hydrogen sulfide contained in the first raw material can be removed, and a purified target gas can be produced. In addition, LPG having high added value can be obtained without discharging a large amount of waste. Furthermore, compared with the case where hydrogen sulfide is removed by the amine absorption method, a regeneration process is unnecessary, the scale of the plant can be reduced, and hydrogen sulfide can be efficiently removed. In addition, even in a small-scale oil and gas field, it is easy to remove hydrogen sulfide in the production area, and energy saving can be achieved.

1, 2, 3 Hydrogen sulfide removal device 10, 18 Raw material supply source 12 Separator 14 Heavy metal removal unit 16 Moisture removal unit 20, 24 First separation unit 22, 26 Second separation unit 30, 32, 34, 36 Hydrogen sulfide Removal unit 40, 42, 44 Mixing unit 50, 52, 54 Absorbent supply source 60 LPG tank 70 to 75 Pump 80, 82, 84, 86 Introduction unit 90, 92 Compressor 101 to 110 Branch L1 to L24, L1 'to L8 ' Piping

Claims (10)

1. A hydrogen sulfide removing unit that removes the hydrogen sulfide by bringing the first raw material containing hydrocarbon and hydrogen sulfide into contact with an oil-soluble hydrogen sulfide absorbent;
   A mixing section for mixing a second raw material containing a high-boiling hydrocarbon having a boiling point equal to or higher than that of propane and a hydrogen sulfide absorbed agent obtained by absorbing the hydrogen sulfide in the hydrogen sulfide absorbent;
   An apparatus for removing hydrogen sulfide, comprising:
2. The hydrogen sulfide removing apparatus according to claim 1, further comprising a first separation unit for separating the high-boiling hydrocarbons from the first raw material in a stage preceding the hydrogen sulfide removal unit.
3. 3. The method according to claim 1, further comprising a second separation unit that separates the high-boiling hydrocarbons from the first raw material treated in the hydrogen sulfide removal unit at a subsequent stage of the hydrogen sulfide removal unit. The hydrogen sulfide removing device described.
4. The apparatus according to claim 2, further comprising an introduction unit that introduces the mixture of the high-boiling point hydrocarbon obtained in the first separation unit and the hydrogen sulfide absorbent into the hydrogen sulfide removal unit. Hydrogen sulfide removal device.
5. A hydrogen sulfide removing step of removing the hydrogen sulfide by bringing a first raw material containing hydrocarbon and hydrogen sulfide into contact with an oil-soluble hydrogen sulfide absorbent;
   Mixing a second raw material containing a high-boiling hydrocarbon having a boiling point equal to or higher than that of propane and a hydrogen sulfide absorbed agent in which the hydrogen sulfide absorbent has absorbed the hydrogen sulfide;
   A method for removing hydrogen sulfide, comprising:
6. 6. The method for removing hydrogen sulfide according to claim 5, further comprising a first separation step for separating the high-boiling hydrocarbons from the first raw material before the hydrogen sulfide removal step.
7. 7. The method according to claim 5, further comprising a second separation step of separating the high-boiling hydrocarbons from the first raw material treated in the hydrogen sulfide removal step after the hydrogen sulfide removal step. The method for removing hydrogen sulfide as described.
8. A premixing step of mixing the high boiling point hydrocarbon obtained in the first separation step and the hydrogen sulfide absorbent, and the hydrogen sulfide removal step is obtained in the premixing step with the first raw material. The method for removing hydrogen sulfide according to claim 6, wherein the mixture is brought into contact with the mixture.
9. 9. The mixing process according to claim 5, wherein, in the mixing step, the second raw material and the hydrogen sulfide-absorbing agent are mixed under a condition that the high boiling point hydrocarbon is in a pressurized liquefied state. The method for removing hydrogen sulfide according to one item.
10. The method for removing hydrogen sulfide according to any one of claims 5 to 8, wherein the high boiling point hydrocarbon is liquid at room temperature.

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