JP6648980B2 - Method for removing carbonyl sulfide in liquid hydrocarbon oil - Google Patents
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- JJWKPURADFRFRB-UHFFFAOYSA-N carbonyl sulfide Chemical compound O=C=S JJWKPURADFRFRB-UHFFFAOYSA-N 0.000 title claims description 188
- 239000007788 liquid Substances 0.000 title claims description 121
- 229930195733 hydrocarbon Natural products 0.000 title claims description 91
- 150000002430 hydrocarbons Chemical class 0.000 title claims description 91
- 239000004215 Carbon black (E152) Substances 0.000 title claims description 90
- 238000000034 method Methods 0.000 title claims description 37
- 238000010521 absorption reaction Methods 0.000 claims description 44
- 230000008929 regeneration Effects 0.000 claims description 12
- 238000011069 regeneration method Methods 0.000 claims description 12
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 claims description 7
- 238000010438 heat treatment Methods 0.000 claims description 7
- 229910000037 hydrogen sulfide Inorganic materials 0.000 claims description 7
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 claims description 6
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims description 6
- 229910052739 hydrogen Inorganic materials 0.000 claims description 4
- HZAXFHJVJLSVMW-UHFFFAOYSA-N 2-Aminoethan-1-ol Chemical compound NCCO HZAXFHJVJLSVMW-UHFFFAOYSA-N 0.000 claims description 3
- UFHFLCQGNIYNRP-UHFFFAOYSA-N Hydrogen Chemical compound [H][H] UFHFLCQGNIYNRP-UHFFFAOYSA-N 0.000 claims description 3
- 239000001257 hydrogen Substances 0.000 claims description 3
- 239000003921 oil Substances 0.000 description 107
- 239000007864 aqueous solution Substances 0.000 description 55
- 239000000243 solution Substances 0.000 description 37
- 239000008346 aqueous phase Substances 0.000 description 31
- 239000012071 phase Substances 0.000 description 30
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 21
- 238000002474 experimental method Methods 0.000 description 20
- 239000007789 gas Substances 0.000 description 19
- VLKZOEOYAKHREP-UHFFFAOYSA-N n-Hexane Chemical compound CCCCCC VLKZOEOYAKHREP-UHFFFAOYSA-N 0.000 description 18
- QQONPFPTGQHPMA-UHFFFAOYSA-N propylene Natural products CC=C QQONPFPTGQHPMA-UHFFFAOYSA-N 0.000 description 17
- 125000004805 propylene group Chemical group [H]C([H])([H])C([H])([*:1])C([H])([H])[*:2] 0.000 description 17
- 230000000052 comparative effect Effects 0.000 description 16
- UGFAIRIUMAVXCW-UHFFFAOYSA-N Carbon monoxide Chemical compound [O+]#[C-] UGFAIRIUMAVXCW-UHFFFAOYSA-N 0.000 description 12
- 229910002091 carbon monoxide Inorganic materials 0.000 description 12
- 229910052717 sulfur Inorganic materials 0.000 description 11
- XLOMVQKBTHCTTD-UHFFFAOYSA-N Zinc monoxide Chemical compound [Zn]=O XLOMVQKBTHCTTD-UHFFFAOYSA-N 0.000 description 10
- 239000003513 alkali Substances 0.000 description 9
- 150000001875 compounds Chemical class 0.000 description 9
- LVTYICIALWPMFW-UHFFFAOYSA-N diisopropanolamine Chemical compound CC(O)CNCC(C)O LVTYICIALWPMFW-UHFFFAOYSA-N 0.000 description 9
- 229940043276 diisopropanolamine Drugs 0.000 description 9
- CRVGTESFCCXCTH-UHFFFAOYSA-N methyl diethanolamine Chemical compound OCCN(C)CCO CRVGTESFCCXCTH-UHFFFAOYSA-N 0.000 description 9
- 238000002156 mixing Methods 0.000 description 9
- 238000000926 separation method Methods 0.000 description 9
- XKRFYHLGVUSROY-UHFFFAOYSA-N Argon Chemical compound [Ar] XKRFYHLGVUSROY-UHFFFAOYSA-N 0.000 description 8
- 238000006243 chemical reaction Methods 0.000 description 8
- 230000001143 conditioned effect Effects 0.000 description 8
- 238000002290 gas chromatography-mass spectrometry Methods 0.000 description 8
- 239000003463 adsorbent Substances 0.000 description 7
- 239000002250 absorbent Substances 0.000 description 6
- 230000002745 absorbent Effects 0.000 description 6
- 230000002378 acidificating effect Effects 0.000 description 6
- 239000000126 substance Substances 0.000 description 6
- 238000000354 decomposition reaction Methods 0.000 description 5
- 239000000203 mixture Substances 0.000 description 5
- 239000012299 nitrogen atmosphere Substances 0.000 description 5
- 238000002360 preparation method Methods 0.000 description 5
- 239000011787 zinc oxide Substances 0.000 description 5
- CURLTUGMZLYLDI-UHFFFAOYSA-N Carbon dioxide Chemical compound O=C=O CURLTUGMZLYLDI-UHFFFAOYSA-N 0.000 description 4
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 4
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 description 4
- 229910052786 argon Inorganic materials 0.000 description 4
- 238000009835 boiling Methods 0.000 description 4
- 230000005587 bubbling Effects 0.000 description 4
- 238000004821 distillation Methods 0.000 description 4
- 239000012153 distilled water Substances 0.000 description 4
- LELOWRISYMNNSU-UHFFFAOYSA-N hydrogen cyanide Chemical compound N#C LELOWRISYMNNSU-UHFFFAOYSA-N 0.000 description 4
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 4
- 238000006386 neutralization reaction Methods 0.000 description 4
- 238000004064 recycling Methods 0.000 description 4
- 239000011593 sulfur Substances 0.000 description 4
- UHOVQNZJYSORNB-UHFFFAOYSA-N Benzene Chemical compound C1=CC=CC=C1 UHOVQNZJYSORNB-UHFFFAOYSA-N 0.000 description 3
- 238000004458 analytical method Methods 0.000 description 3
- 238000005516 engineering process Methods 0.000 description 3
- 230000007062 hydrolysis Effects 0.000 description 3
- 238000006460 hydrolysis reaction Methods 0.000 description 3
- 239000012535 impurity Substances 0.000 description 3
- 239000003345 natural gas Substances 0.000 description 3
- 239000000047 product Substances 0.000 description 3
- 238000001179 sorption measurement Methods 0.000 description 3
- 150000003464 sulfur compounds Chemical class 0.000 description 3
- IZXIZTKNFFYFOF-UHFFFAOYSA-N 2-Oxazolidone Chemical compound O=C1NCCO1 IZXIZTKNFFYFOF-UHFFFAOYSA-N 0.000 description 2
- LFQSCWFLJHTTHZ-UHFFFAOYSA-N Ethanol Chemical compound CCO LFQSCWFLJHTTHZ-UHFFFAOYSA-N 0.000 description 2
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 2
- 239000001569 carbon dioxide Substances 0.000 description 2
- 229910002092 carbon dioxide Inorganic materials 0.000 description 2
- 239000012159 carrier gas Substances 0.000 description 2
- RWGFKTVRMDUZSP-UHFFFAOYSA-N cumene Chemical compound CC(C)C1=CC=CC=C1 RWGFKTVRMDUZSP-UHFFFAOYSA-N 0.000 description 2
- 230000006866 deterioration Effects 0.000 description 2
- ZBCBWPMODOFKDW-UHFFFAOYSA-N diethanolamine Chemical compound OCCNCCO ZBCBWPMODOFKDW-UHFFFAOYSA-N 0.000 description 2
- 239000007791 liquid phase Substances 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- NCWQJOGVLLNWEO-UHFFFAOYSA-N methylsilicon Chemical compound [Si]C NCWQJOGVLLNWEO-UHFFFAOYSA-N 0.000 description 2
- 239000001301 oxygen Substances 0.000 description 2
- 229910052760 oxygen Inorganic materials 0.000 description 2
- 239000001294 propane Substances 0.000 description 2
- 230000000630 rising effect Effects 0.000 description 2
- 238000007086 side reaction Methods 0.000 description 2
- 239000011949 solid catalyst Substances 0.000 description 2
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 1
- QPLDLSVMHZLSFG-UHFFFAOYSA-N Copper oxide Chemical compound [Cu]=O QPLDLSVMHZLSFG-UHFFFAOYSA-N 0.000 description 1
- 239000005751 Copper oxide Substances 0.000 description 1
- XSQUKJJJFZCRTK-UHFFFAOYSA-N Urea Chemical compound NC(N)=O XSQUKJJJFZCRTK-UHFFFAOYSA-N 0.000 description 1
- HCHKCACWOHOZIP-UHFFFAOYSA-N Zinc Chemical compound [Zn] HCHKCACWOHOZIP-UHFFFAOYSA-N 0.000 description 1
- 239000005083 Zinc sulfide Substances 0.000 description 1
- 239000003377 acid catalyst Substances 0.000 description 1
- 150000001412 amines Chemical class 0.000 description 1
- 239000012298 atmosphere Substances 0.000 description 1
- 239000001273 butane Substances 0.000 description 1
- 239000006227 byproduct Substances 0.000 description 1
- 239000004202 carbamide Substances 0.000 description 1
- 229910052799 carbon Inorganic materials 0.000 description 1
- 125000004432 carbon atom Chemical group C* 0.000 description 1
- 125000002915 carbonyl group Chemical group [*:2]C([*:1])=O 0.000 description 1
- 239000003054 catalyst Substances 0.000 description 1
- 238000004523 catalytic cracking Methods 0.000 description 1
- 229910000431 copper oxide Inorganic materials 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 230000000593 degrading effect Effects 0.000 description 1
- XJFYWGIWEYQMPK-UHFFFAOYSA-N ethanol;urea Chemical compound CCO.NC(N)=O XJFYWGIWEYQMPK-UHFFFAOYSA-N 0.000 description 1
- 238000004231 fluid catalytic cracking Methods 0.000 description 1
- 238000005194 fractionation Methods 0.000 description 1
- 239000000295 fuel oil Substances 0.000 description 1
- 239000001307 helium Substances 0.000 description 1
- 229910052734 helium Inorganic materials 0.000 description 1
- SWQJXJOGLNCZEY-UHFFFAOYSA-N helium atom Chemical compound [He] SWQJXJOGLNCZEY-UHFFFAOYSA-N 0.000 description 1
- -1 hydrogen sulfide ions Chemical class 0.000 description 1
- 238000000752 ionisation method Methods 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- IJDNQMDRQITEOD-UHFFFAOYSA-N n-butane Chemical compound CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 1
- OFBQJSOFQDEBGM-UHFFFAOYSA-N n-pentane Natural products CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 1
- 238000010525 oxidative degradation reaction Methods 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 238000005504 petroleum refining Methods 0.000 description 1
- ZNNZYHKDIALBAK-UHFFFAOYSA-M potassium thiocyanate Chemical compound [K+].[S-]C#N ZNNZYHKDIALBAK-UHFFFAOYSA-M 0.000 description 1
- 229940116357 potassium thiocyanate Drugs 0.000 description 1
- 238000010248 power generation Methods 0.000 description 1
- 239000002994 raw material Substances 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 238000003756 stirring Methods 0.000 description 1
- QAOWNCQODCNURD-UHFFFAOYSA-N sulfuric acid Substances OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 description 1
- 125000000383 tetramethylene group Chemical group [H]C([H])([*:1])C([H])([H])C([H])([H])C([H])([H])[*:2] 0.000 description 1
- 229910052725 zinc Inorganic materials 0.000 description 1
- 239000011701 zinc Substances 0.000 description 1
- 229910052984 zinc sulfide Inorganic materials 0.000 description 1
- DRDVZXDWVBGGMH-UHFFFAOYSA-N zinc;sulfide Chemical compound [S-2].[Zn+2] DRDVZXDWVBGGMH-UHFFFAOYSA-N 0.000 description 1
Description
本発明は、液体炭化水素油中の硫化カルボニルを除去する方法に関する。 The present invention relates to a method for removing carbonyl sulfide in a liquid hydrocarbon oil.
近年、石油化学原料としてのプロピレンの需要が増加している。需要の増加を受けて、重質油の接触分解生成物から得られるＣ３留分の分離等によって、プロピレンの供給量が確保されている。しかし、このようにして得られるプロピレンは、硫黄化合物等の不純物を多量に含有しており、特に数ｐｐｍないし数十ｐｐｍの硫化カルボニル（化学式：ＣＯＳ）を含有している。 In recent years, demand for propylene as a petrochemical raw material has been increasing. In response to the increase in demand, the supply amount of propylene is secured by, for example, separating a C3 fraction obtained from a catalytic cracking product of heavy oil. However, the propylene thus obtained contains a large amount of impurities such as sulfur compounds, and particularly contains several ppm to several tens ppm of carbonyl sulfide (chemical formula: COS).
プロピレンの特定の用途（例えば、プロピレン及びベンゼンを用いたキュメンの製造）では、プロピレンに混入したＣＯＳによって触媒（例えば、酸触媒）が被毒してしまう。このようなプロピレン中の不純物に起因する問題を解決するために、従来、プロピレン中の不純物は、蒸留によって分離・除去されてきた。しかし、ＣＯＳの沸点（−５０．２℃）はプロピレンの沸点（−４７．７℃）に近いので、蒸留等の沸点差に基づく方法によってＣＯＳをプロピレンから分離・除去することは非常に困難である。同様の問題は、プロピレン以外の炭化水素油においてもある。 In certain applications of propylene (eg, the production of cumene using propylene and benzene), catalysts (eg, acid catalysts) are poisoned by COS incorporated into propylene. In order to solve such problems caused by impurities in propylene, impurities in propylene have conventionally been separated and removed by distillation. However, since the boiling point of COS (−50.2 ° C.) is close to the boiling point of propylene (−47.7 ° C.), it is very difficult to separate and remove COS from propylene by a method based on a boiling point difference such as distillation. is there. A similar problem exists with hydrocarbon oils other than propylene.
蒸留以外にも、炭化水素油中に存在するＣＯＳを除去する方法はある。例えば、従来、炭化水素油を吸着剤と接触させる方法が検討され、工業的に実用化されている。例えば、下記特許文献１は、液体状のプロピレンを０〜１００℃の温度で酸化亜鉛と接触させて、プロピレン中のＣＯＳを除去する方法を開示している。また、下記特許文献２は、液体状のプロピレンを０〜８０℃の温度で酸化銅及び酸化亜鉛に接触させて、プロピレン中の一酸化炭素（ＣＯ）及びＣＯＳを同時に除去する方法を開示している。 Other than distillation, there is a method for removing COS present in hydrocarbon oil. For example, conventionally, a method of contacting a hydrocarbon oil with an adsorbent has been studied and has been industrially put to practical use. For example, Patent Literature 1 below discloses a method of removing COS in propylene by bringing liquid propylene into contact with zinc oxide at a temperature of 0 to 100 ° C. Patent Document 2 below discloses a method for simultaneously removing carbon monoxide (CO) and COS in propylene by bringing liquid propylene into contact with copper oxide and zinc oxide at a temperature of 0 to 80 ° C. I have.
また、ＣＯＳを硫化水素（Ｈ２Ｓ）に分解し、このＨ２Ｓを吸着剤で除去する方法も知られている。例えば、下記特許文献３及び４は、ＣＯＳ及びシアン化水素（ＨＣＮ）を含む混合ガスを、スチームとともに、金属を含む固体触媒に接触させる方法を開示している。 There is also known a method of decomposing COS into hydrogen sulfide (H 2 S) and removing the H 2 S with an adsorbent. For example, Patent Documents 3 and 4 below disclose a method in which a mixed gas containing COS and hydrogen cyanide (HCN) is brought into contact with a metal-containing solid catalyst together with steam.
さらに、炭化水素油中に存在する硫黄化合物をＨ２Ｓに分解し除去する方法も知られている。例えば、下記特許文献５は、３００℃程度の温度下で、炭化水素油及び水素の混合物を固体触媒に接触させる水素化脱硫が知られている。 Further, a method of decomposing and removing sulfur compounds present in hydrocarbon oil into H 2 S is also known. For example, Patent Document 5 described below discloses hydrodesulfurization in which a mixture of hydrocarbon oil and hydrogen is brought into contact with a solid catalyst at a temperature of about 300 ° C.
上記特許文献１及び２の方法では、酸化亜鉛及びＨ２Ｓの化学反応により硫化亜鉛が形成される。この反応により、理論上の吸着容量分の硫黄を吸着剤（酸化亜鉛に由来する亜鉛）に吸着させることが可能である。しかし、酸化亜鉛がＣＯＳと接触しても、両物質の反応は十分に進行しない。その結果、理論上の吸着容量に満たないわずかな硫黄が吸着剤に吸着するに過ぎない。また、吸着剤の寿命が短い。吸着剤の吸着容量が小さく、その寿命が短いため、吸着剤の交換頻度が多くなってしまう。 In the methods of Patent Documents 1 and 2, zinc sulfide is formed by a chemical reaction between zinc oxide and H 2 S. By this reaction, it is possible to cause the adsorbent (zinc derived from zinc oxide) to adsorb sulfur in the theoretical adsorption capacity. However, even when zinc oxide comes into contact with COS, the reaction between the two substances does not proceed sufficiently. As a result, only a small amount of sulfur, less than the theoretical adsorption capacity, adsorbs on the adsorbent. In addition, the life of the adsorbent is short. Since the adsorbent has a small adsorption capacity and a short life, the replacement frequency of the adsorbent increases.
上記特許文献３及び４の方法では、スチームによる加水分解により、ＣＯＳをＨ２Ｓと二酸化炭素（ＣＯ２）とに分解する。この方法は、ガスタービン発電に使用される混合ガス中のＣＯＳをＨ２Ｓに分解するための方法であり、１１０〜２５０℃の反応温度を必要とする。したがって、特許文献３及び４の方法を液体炭化水素油に応用する場合、液体炭化水素油の加熱により、炭化水素油が気化してしまう。よって、気化された炭化水素油を再液化する工程も必要である。以上のように、上記特許文献３及び４の方法の場合、液体炭化水素油からＣＯＳを除去するために要する工程が複雑である。また、ＣＯＳの除去に多大なエネルギー（熱）が消費される。ＣＯＳの除去に要する設備にコストもかかる。 In the methods of Patent Documents 3 and 4, COS is decomposed into H 2 S and carbon dioxide (CO 2 ) by hydrolysis with steam. This method is a method for degrading COS in the mixed gas used in the gas turbine power generation H 2 S, which requires a reaction temperature of 110 to 250 ° C.. Therefore, when the methods of Patent Documents 3 and 4 are applied to liquid hydrocarbon oil, the hydrocarbon oil vaporizes due to heating of the liquid hydrocarbon oil. Therefore, a step of reliquefying the vaporized hydrocarbon oil is also required. As described above, in the methods of Patent Documents 3 and 4, the steps required to remove COS from the liquid hydrocarbon oil are complicated. In addition, a great deal of energy (heat) is consumed to remove COS. The equipment required for COS removal is costly.
上記特許文献５の方法は、ＣＯＳに限らず硫黄化合物全般の分解に適用できる。しかし、上記特許文献５の方法は、大がかりな設備を要する。したがって、特許文献５の方法を、プロパン又はプロピレン等の軽質炭化水素油中のＣＯＳの分解に適用するためには、コストがかかり過ぎる。 The method of Patent Document 5 can be applied to decomposition of not only COS but also sulfur compounds in general. However, the method of Patent Document 5 requires extensive equipment. Therefore, it is too costly to apply the method of Patent Document 5 to the decomposition of COS in light hydrocarbon oil such as propane or propylene.
本発明は、上述した事情に鑑み、液体の炭化水素油に含まれる硫化カルボニルを容易に除去することができる方法を提供することを目的とする。 The present invention has been made in view of the above circumstances, and has as its object to provide a method capable of easily removing carbonyl sulfide contained in a liquid hydrocarbon oil.
本発明者らは、液体炭化水素油中に存在する硫化カルボニルの除去方法について、上記課題を解決すべく鋭意研究を重ねた結果、ある特定のアルカノールアミンの水溶液と、液体炭化水素油とを接触させることにより、液体炭化水素油に含まれるＣＯＳを除去し得ることを見出し、本発明を完成させた。 The present inventors have conducted intensive studies on a method for removing carbonyl sulfide present in liquid hydrocarbon oil in order to solve the above problems, and as a result, contacted an aqueous solution of a specific alkanolamine with liquid hydrocarbon oil. By doing so, it was found that COS contained in the liquid hydrocarbon oil could be removed, and the present invention was completed.
すなわち、本発明は、液体炭化水素油を吸収液に接触させることにより、液体炭化水素油に含まれる硫化カルボニルを液体炭化水素油から除去する吸収工程を備え、吸収液が、モノエタノールアミン又はジエタノールアミンのうち少なくとも一方の水溶液である、液体炭化水素油中のＣＯＳを除去する方法を提供する。以下では、モノエタノールアミンを、「ＭＥＡ」という場合がある。ジエタノールアミンを、「ＤＥＡ」という場合がある。 That is, the present invention includes an absorption step of removing carbonyl sulfide contained in the liquid hydrocarbon oil from the liquid hydrocarbon oil by bringing the liquid hydrocarbon oil into contact with the absorption liquid, wherein the absorption liquid is monoethanolamine or diethanolamine. A method for removing COS in a liquid hydrocarbon oil, which is at least one aqueous solution. Hereinafter, monoethanolamine may be referred to as “MEA”. Diethanolamine is sometimes referred to as “DEA”.
吸収液がＭＥＡの水溶液である場合、吸収工程では、硫化カルボニルを硫化水素に分解し、硫化水素を吸収液に吸収させてよい。 When the absorbing solution is an aqueous solution of MEA, in the absorbing step, carbonyl sulfide may be decomposed into hydrogen sulfide and hydrogen sulfide may be absorbed by the absorbing solution.
吸収液がＭＥＡの水溶液である場合、本発明に係る上記方法は、吸収工程の後、吸収液を加熱して硫化水素を吸収液から放出させる再生工程を更に備えていてもよい。 When the absorbing liquid is an aqueous solution of MEA, the method according to the present invention may further include, after the absorbing step, a regeneration step of heating the absorbing liquid to release hydrogen sulfide from the absorbing liquid.
吸収液がＭＥＡの水溶液である場合、本発明に係る上記方法は、再生工程において加熱された吸収液を、吸収工程における吸収液として再利用する再利用工程を更に備えていてもよい。 When the absorbing solution is an aqueous solution of MEA, the method according to the present invention may further include a recycling step of recycling the absorbing solution heated in the regeneration step as the absorbing solution in the absorbing step.
本発明によれば、液体の炭化水素油に含まれるカルボニルを容易に除去することができる。 According to the present invention, carbonyl contained in a liquid hydrocarbon oil can be easily removed.
以下、本発明の好適な実施形態について説明する。ただし、本発明は下記の実施形態に何ら限定されるものではない。 Hereinafter, preferred embodiments of the present invention will be described. However, the present invention is not limited to the following embodiments.
本実施形態に係る方法は、液体炭化水素油中の硫化カルボニル（ＣＯＳ）を除去する方法であり、以下に詳述する吸収工程を備える。 The method according to the present embodiment is a method for removing carbonyl sulfide (COS) in a liquid hydrocarbon oil, and includes an absorption step described in detail below.
吸収工程では、液体炭化水素油を吸収液に接触させ、液体炭化水素油に含まれるＣＯＳを液体炭化水素油から除去する。液体炭化水素油に含まれるＣＯＳそのものが、吸収液に吸収されてもよく、ＣＯＳの化学的変化によって生じた物質が、吸収液に吸収されてもよい。 In the absorption step, the liquid hydrocarbon oil is brought into contact with the absorption liquid to remove COS contained in the liquid hydrocarbon oil from the liquid hydrocarbon oil. COS itself contained in the liquid hydrocarbon oil may be absorbed in the absorbing liquid, or a substance generated by a chemical change of COS may be absorbed in the absorbing liquid.
ＣＯＳは、常温常圧で無色の気体である。ＣＯＳは、石油精製等による液体炭化水素油の製造に伴って副生される。ＣＯＳは、例えば、炭化水素ガスの液化に伴って、炭化水素に取り込まれる。または、液体炭化水素油がＣＯＳ含有ガスと接触するにより、ＣＯＳが液体炭化水素油に溶解することもある。 COS is a colorless gas at normal temperature and normal pressure. COS is produced as a by-product of the production of liquid hydrocarbon oil by petroleum refining and the like. COS is taken into hydrocarbons, for example, as the hydrocarbon gas is liquefied. Alternatively, COS may be dissolved in the liquid hydrocarbon oil when the liquid hydrocarbon oil comes into contact with the COS-containing gas.
液体炭化水素油は、ＣＯＳを含有する液体炭化水素であれば、特に制限されるものではない。液体炭化水素油は、例えば、天然ガス又は石油随伴ガスから得られる炭化水素の留分であってよい。液体炭化水素油は、炭素数が５以上であり、沸点が１８０℃以下である留分であってよい。このような液体炭化水素油は、例えば、常圧蒸留装置を用いた炭化水素の分留によって得られる。液体炭化水素油を、原油の分留によって得てもよい。常温常圧で気体である炭化水素を、加圧して液化することにより、液体炭化水素油として用いてもよい。常温常圧で気体である炭化水素とは、例えば、プロパン、プロピレン、ブタン及びブチレンからなる群より選ばれる少なくとも一種であってよい。これらの炭化水素ガスは、天然ガスであってもよく、流動接触分解装置（ＦＣＣ装置）から生産されるガスであってもよい。液体炭化水素油中のＣＯＳの含有量は、液体炭化水素油の種類によって異なり、特に限定されないが、例えば数質量ｐｐｍ〜１００質量ｐｐｍ、数μｇ／ｍｌ〜６０μｇ／ｍｌであってよい。 The liquid hydrocarbon oil is not particularly limited as long as it is a liquid hydrocarbon containing COS. The liquid hydrocarbon oil may be, for example, a hydrocarbon fraction obtained from natural gas or petroleum-associated gas. The liquid hydrocarbon oil may be a fraction having 5 or more carbon atoms and a boiling point of 180 ° C. or less. Such a liquid hydrocarbon oil is obtained, for example, by fractionating a hydrocarbon using an atmospheric distillation apparatus. Liquid hydrocarbon oils may be obtained by fractionation of crude oil. A hydrocarbon which is a gas at normal temperature and normal pressure may be used as a liquid hydrocarbon oil by liquefying under pressure. The hydrocarbon that is a gas at normal temperature and normal pressure may be, for example, at least one selected from the group consisting of propane, propylene, butane, and butylene. These hydrocarbon gases may be natural gas or gases produced from a fluid catalytic cracking unit (FCC unit). The content of COS in the liquid hydrocarbon oil differs depending on the type of the liquid hydrocarbon oil and is not particularly limited, but may be, for example, several ppm to 100 ppm, and several μg / ml to 60 μg / ml.
本実施形態で用いる吸収液は、ＭＥＡ又はＤＥＡのうち少なくとも一方を含む水溶液である。吸収液は、ＭＥＡのみを含む水であってよい。ＤＥＡのみを含む水であってもよい。ＭＥＡ及びＤＥＡの両方を含む水であってもよい。以下、液体炭化水素油に含まれるＣＯＳを吸収液によって除去する機構について説明する。 The absorbing liquid used in the present embodiment is an aqueous solution containing at least one of MEA and DEA. The absorbing liquid may be water containing only MEA. Water containing only DEA may be used. It may be water containing both MEA and DEA. Hereinafter, a mechanism for removing COS contained in the liquid hydrocarbon oil by the absorption liquid will be described.
吸収液としてＭＥＡ水溶液を用いる場合、ＣＯＳが液体炭化水素油から除去される機構は、例えば以下の２つの化学反応式によって表される。ただし、以下の化学反応式は本発明者らの推察に基づくものであり、ＣＯＳの除去機構は、下記に限定されるものではない。
液体炭化水素油を吸収液に接触させると、液体炭化水素油（油相）とＭＥＡ水溶液（水相）との界面付近において、上記のようにＣＯＳとＭＥＡ（ＮＨ２−（ＣＨ２）２−ＯＨ）とが接触して反応する。その結果、２−オキサゾリドン又はエタノールウレア（ウレア型生成物）、並びにＨ２Ｓ及びＣＯ２が生成する。なお、上記化学反応式中では、ＣＯ２を省略している。２−オキサゾリドン又はウレア型生成物は、界面を通じて油相から水相へ移動する。Ｈ２Ｓ及びＣＯ２は弱酸性を有し、ＭＥＡ水溶液は弱塩基性を有する。したがって、Ｈ２Ｓ及びＣＯ２はＭＥＡと中和反応を起こす。Ｈ２Ｓは、中和反応により、硫化水素イオン（ＨＳ−）となり、水相へ吸収される。ＣＯ２は、中和反応により、炭酸水素イオン（ＨＣＯ３ −）となり、水相へ吸収される。以上の機序により、液体炭化水素油中のＣＯＳが除去される。上記化学反応式が示す通り、ＭＥＡ水溶液によるＣＯＳの除去は、ＣＯＳの化学的変化（分解）を伴う。つまり、必ずしも全てのＣＯＳが、その分子構造を維持した状態で、ＭＥＡ水溶液へ吸収されるわけではない。もちろん、少なくとも一部のＣＯＳは、その分子構造を維持した状態で、ＭＥＡ水溶液へ吸収されてよい。以下では、ＣＯＳの「分解」又は「除去」と、ＣＯＳの「吸収」とを、必ずしも区別しない。 When the liquid hydrocarbon oil is brought into contact with the absorbing liquid, the COS and MEA (NH 2 — (CH 2 ) 2 −) as described above near the interface between the liquid hydrocarbon oil (oil phase) and the MEA aqueous solution (water phase). OH) and reacts. As a result, 2-oxazolidone or ethanol urea (urea-type product), as well as H 2 S and CO 2 are produced. In the above chemical reaction formula, CO 2 is omitted. The 2-oxazolidone or urea type product moves from the oil phase to the aqueous phase through the interface. H 2 S and CO 2 have weak acidity, and the MEA aqueous solution has weak basicity. Therefore, H 2 S and CO 2 cause a neutralization reaction with MEA. H 2 S is converted into hydrogen sulfide ions (HS − ) by the neutralization reaction, and is absorbed in the aqueous phase. CO 2 is converted into hydrogen carbonate ion (HCO 3 − ) by the neutralization reaction, and is absorbed in the aqueous phase. By the above mechanism, COS in the liquid hydrocarbon oil is removed. As indicated by the above chemical reaction formula, removal of COS by the MEA aqueous solution involves a chemical change (decomposition) of COS. That is, not all COS is necessarily absorbed into the MEA aqueous solution while maintaining its molecular structure. Of course, at least some of the COS may be absorbed into the MEA aqueous solution while maintaining its molecular structure. In the following, “decomposition” or “removal” of COS and “absorption” of COS are not necessarily distinguished.
吸収液におけるＭＥＡの含有量は、特に制限されない。吸収液におけるＭＥＡの含有量は、例えば、５〜５０質量％であってよい。ＭＥＡの含有量が５質量％以上であれば、吸収液によるＣＯＳの吸収が促進され易い。一方、ＭＥＡの含有量が５０質量％以下であれば、吸収液の粘度の低下により、吸収液を操作し易くなり、液液分離（油相及び水相の分離）等の作業効率が向上する。同様の理由から、吸収液におけるＭＥＡの含有量は、１５〜４０質量％であってもよい。 The content of MEA in the absorbing solution is not particularly limited. The content of MEA in the absorbing solution may be, for example, 5 to 50% by mass. When the content of MEA is 5% by mass or more, absorption of COS by the absorbing solution is easily promoted. On the other hand, when the content of MEA is 50% by mass or less, the viscosity of the absorbing solution is reduced, so that the absorbing solution can be easily operated and the working efficiency such as liquid-liquid separation (separation of the oil phase and the aqueous phase) is improved. . For the same reason, the content of MEA in the absorbing solution may be 15 to 40% by mass.
吸収液がＭＥＡ水溶液である場合、上述した吸収工程の後に、再生工程を行ってもよい。再生工程では、ＭＥＡ水溶液を加熱することにより、ＭＥＡ水溶液中の弱酸性成分（Ｈ２Ｓ及びＣＯ２）をＭＥＡ水溶液から放出させる。その結果、ＭＥＡは、弱酸性成分に供されず、ＣＯＳの分解反応へ供される。以上のように、「再生」とは、ＭＥＡ水溶液から弱酸性成分を除去することより、弱酸性成分及びＭＥＡの中和反応を抑制することを意味する。再生工程におけるＭＥＡ水溶液の加熱温度は、特に制限されないが、１００〜１４０℃であってよい。加熱温度が１００℃以上であれば、上記弱酸性成分の放出（ＭＥＡ水溶液の再生）が促進され易い。加熱温度が１４０℃以下であれば、ＭＥＡ水溶液の変質及び装置の腐食が抑制され易い。ここで装置とは、本実施形態に係る方法を実施するための反応器と言い換えてよい。 When the absorbing liquid is an aqueous MEA solution, a regeneration step may be performed after the above-described absorption step. In the regeneration step, the weakly acidic components (H 2 S and CO 2 ) in the MEA aqueous solution are released from the MEA aqueous solution by heating the MEA aqueous solution. As a result, the MEA is not subjected to the weakly acidic component but is subjected to the COS decomposition reaction. As described above, “regeneration” means that the neutralization reaction of the weakly acidic component and the MEA is suppressed by removing the weakly acidic component from the MEA aqueous solution. The heating temperature of the MEA aqueous solution in the regeneration step is not particularly limited, but may be 100 to 140 ° C. When the heating temperature is 100 ° C. or higher, release of the weakly acidic component (regeneration of the MEA aqueous solution) is easily promoted. When the heating temperature is 140 ° C. or lower, deterioration of the MEA aqueous solution and corrosion of the device are easily suppressed. Here, the apparatus may be referred to as a reactor for performing the method according to the present embodiment.
吸収液がＭＥＡ水溶液である場合、上述した再生工程の後、再利用工程を行ってもよい。再利用工程では、再生工程において加熱されたＭＥＡ水溶液を、吸収工程における吸収液として再利用する。つまり、再利用工程では、液体炭化水素油を、再生されたＭＥＡ水溶液に接触させる。その結果、液体炭化水素油中のＣＯＳが、再生後のＭＥＡ水溶液によって除去する。再生工程及び再利用工程を実施することにより、ＭＥＡ水溶液の消耗が抑制され、新しいＭＥＡ水溶液（未使用のＭＥＡ水溶液）の補充量を減らせる。 When the absorbing solution is an aqueous MEA solution, a recycling step may be performed after the above-described regeneration step. In the reuse step, the MEA aqueous solution heated in the regeneration step is reused as an absorbing liquid in the absorption step. That is, in the recycling step, the liquid hydrocarbon oil is brought into contact with the regenerated MEA aqueous solution. As a result, COS in the liquid hydrocarbon oil is removed by the regenerated MEA aqueous solution. By performing the regeneration step and the reuse step, consumption of the MEA aqueous solution is suppressed, and the amount of replenishment of a new MEA aqueous solution (an unused MEA aqueous solution) can be reduced.
吸収液として、ＭＥＡ水溶液ではなくＤＥＡ水溶液を用いる場合、液体炭化水素油に含まれるＣＯＳは、ＤＥＡ水溶液に接触してＤＥＡと化学的に作用し、ＤＥＡ水溶液中に吸収される。しかし、ＤＥＡ水溶液を用いた場合、ＣＯＳは必ずしもＨ２Ｓ及びＣＯ２に分解されない。 When a DEA aqueous solution is used as the absorbing liquid instead of the MEA aqueous solution, COS contained in the liquid hydrocarbon oil comes into contact with the DEA aqueous solution to chemically act on the DEA and is absorbed in the DEA aqueous solution. However, when a DEA aqueous solution is used, COS is not necessarily decomposed into H 2 S and CO 2 .
吸収液におけるＤＥＡの含有量は、特に制限されない。吸収液におけるＤＥＡの含有量は、例えば、３〜５０質量％であってよい。ＤＥＡの含有量が３質量％以上であれば、吸収液によるＣＯＳの吸収が促進され易い。一方。ＤＥＡの含有量が５０質量％以下であれば、吸収液の粘度の低下により、吸収液を操作し易くなり、液液分離（油相及び水相の分離）等の作業効率が向上する。同様の理由から、吸収液におけるＤＥＡの含有量は、５〜４０質量％であってよい。 The content of DEA in the absorbing solution is not particularly limited. The content of DEA in the absorbing solution may be, for example, 3 to 50% by mass. When the content of DEA is 3% by mass or more, absorption of COS by the absorbing solution is easily promoted. on the other hand. If the content of DEA is 50% by mass or less, the viscosity of the absorbing solution is reduced, so that the absorbing solution can be easily operated and the working efficiency such as liquid-liquid separation (separation of oil phase and aqueous phase) is improved. For the same reason, the content of DEA in the absorbing solution may be 5 to 40% by mass.
液体炭化水素油と吸収液との混合比率は、液体炭化水素油中のＣＯＳの含有量に応じて調整すればよく、特に限定されない。吸収液中のＭＥＡ又はＤＥＡのモル数がＡであり、液体炭化水素油中のＣＯＳのモル数がＢである場合、Ｂ／Ａが０．１〜０．６となるように、液体炭化水素油及び吸収液それぞれの量を調整してよい。Ｂ／Ａが小さ過ぎると、吸収液の量が過大になる傾向がある。一方、Ｂ／Ａが大き過ぎると、吸収液によるＣＯＳの吸収の効率が低下する傾向がある。 The mixing ratio between the liquid hydrocarbon oil and the absorbing liquid may be adjusted according to the content of COS in the liquid hydrocarbon oil, and is not particularly limited. When the number of moles of MEA or DEA in the absorbing liquid is A and the number of moles of COS in the liquid hydrocarbon oil is B, the liquid hydrocarbon is adjusted so that B / A becomes 0.1 to 0.6. The amount of each of the oil and the absorbing liquid may be adjusted. If B / A is too small, the amount of the absorbing solution tends to be excessive. On the other hand, if B / A is too large, the absorption efficiency of COS by the absorbing solution tends to decrease.
液体炭化水素油と吸収液とを接触させ、混合させる方法は、特に限定されない。例えば、ラインミキサー、又は機械的撹拌機等の種々の接触方法及び混合方法を用いてよい。特に、オリフィス又はバッフルミキサーによって、液体炭化水素油と吸収液とを接触させ、混合させた場合、ＣＯＳの吸収効率が向上し易い。液体炭化水素油と吸収液とを接触させ、混合する時の温度（接触・混合温度）は、特に限定されない。接触・混合温度は、例えば、２０〜６０℃であってよい。接触・混合温度が２０℃以上であれば、ＣＯＳの吸収効率が向上し易い。接触・混合温度が６０℃以下であれば、ＭＥＡ又はＤＥＡの劣化が抑制され易く、副反応も抑制され易い。ここで副反応とは、微量の酸素によるＭＥＡ又はＤＥＡの酸化劣化、及びＭＥＡ又はＤＥＡと酸性ガスとの接触による熱安定性アミンの生成である。同様の理由から、接触・混合温度は、４０〜６０℃であってもよい。接触・混合後の液体炭化水素油及び吸収液を一定時間静置することで、油水分離が起こり、上記の通り、油相中のＣＯＳが水相へ吸収される。 The method of bringing the liquid hydrocarbon oil and the absorbing liquid into contact with each other and mixing them is not particularly limited. For example, various contact methods and mixing methods such as a line mixer or a mechanical stirrer may be used. In particular, when the liquid hydrocarbon oil and the absorbing liquid are brought into contact with and mixed by an orifice or a baffle mixer, the absorption efficiency of COS tends to be improved. The temperature (contact / mixing temperature) at which the liquid hydrocarbon oil is brought into contact with the absorbing liquid and mixed is not particularly limited. The contact / mixing temperature may be, for example, 20 to 60 ° C. When the contact / mixing temperature is 20 ° C. or higher, the COS absorption efficiency is easily improved. When the contact / mixing temperature is 60 ° C. or less, deterioration of MEA or DEA is easily suppressed, and side reactions are easily suppressed. Here, the side reaction is the oxidative degradation of MEA or DEA by a trace amount of oxygen, and the generation of a heat-stable amine by contact of MEA or DEA with an acidic gas. For the same reason, the contact / mixing temperature may be 40 to 60 ° C. By allowing the liquid hydrocarbon oil and the absorbent after contact and mixing to stand for a certain period of time, oil-water separation occurs, and as described above, COS in the oil phase is absorbed into the water phase.
以上の本実施形態に係る方法によれば、液体炭化水素油中に存在するＣＯＳを、簡便な操作により効率良く除去することができる。具体的には、上記の方法は、スチームによるＣＯＳガスの加水分解によりＨ２Ｓガスを生成させるのではなく、液体（液体炭化水素油）中のＣＯＳを別の液体（吸収液）へ吸収させるものである。したがって、本実施形態に係る方法においては、高温におけるＣＯＳの加水分解のために液体炭化水素油を気化させたり、ＣＯＳの分解後に炭化水素油を再液化させたりする必要がない。 According to the method according to the present embodiment described above, COS present in the liquid hydrocarbon oil can be efficiently removed by a simple operation. Specifically, the above-mentioned method does not generate H 2 S gas by hydrolysis of COS gas by steam, but absorbs COS in a liquid (liquid hydrocarbon oil) into another liquid (absorbing liquid). Things. Therefore, in the method according to the present embodiment, it is not necessary to vaporize the liquid hydrocarbon oil for the hydrolysis of COS at a high temperature or to reliquefy the hydrocarbon oil after the COS is decomposed.
ＭＥＡ又はＤＥＡ等のアルカノールアミンは、常温において固体であったり、粘度の高い液体であったりする。したがって、アルカノールアミンそのものを万遍無く液体炭化水素油と接触させたり混合したりすることは容易ではない。したがって、アルカノールアミンだけを用いて液体炭化水素油中のＣＯＳを除去することは困難である。一方、本実施形態に係る方法においては、吸収液が水溶液であるため、吸収液中のＭＥＡ又はＤＥＡの含有量の調整により、吸収液の粘度を容易に制御することが可能である。吸収液の粘度の制御により、吸収液を液体炭化水素油と容易に且つ均一に接触させ、且つ混合することができる。また、吸収液の粘度の制御により、ＣＯＳを吸収した吸収液（水相）と、ＣＯＳが除去された液体炭化水素油（油相）とを、容易に分離することができる。つまり、液液分離（水相及び油相の分離）の工程の効率が向上する。 Alkanolamines such as MEA or DEA are solid at room temperature or liquid with high viscosity. Therefore, it is not easy to uniformly contact and mix the alkanolamine itself with the liquid hydrocarbon oil. Therefore, it is difficult to remove COS in liquid hydrocarbon oil using only alkanolamine. On the other hand, in the method according to the present embodiment, since the absorbing solution is an aqueous solution, the viscosity of the absorbing solution can be easily controlled by adjusting the content of MEA or DEA in the absorbing solution. By controlling the viscosity of the absorbing liquid, the absorbing liquid can be easily and uniformly contacted with and mixed with the liquid hydrocarbon oil. Further, by controlling the viscosity of the absorbing liquid, the absorbing liquid (aqueous phase) that has absorbed COS and the liquid hydrocarbon oil (oil phase) from which COS has been removed can be easily separated. That is, the efficiency of the liquid-liquid separation (separation of the aqueous phase and the oil phase) is improved.
以上、本発明の一実施形態について説明したが、本発明は上記の実施形態に限定されない。 As mentioned above, although one Embodiment of this invention was described, this invention is not limited to said Embodiment.
例えば、吸収液は、アルカリ化合物を含んでもよい。吸収液がアルカリ化合物を含有することにより、ＣＯＳ又はＣＯＳに由来するＨ２Ｓがアルカリ化合物と化学的に作用して、ＣＯＳの吸収が促進される傾向がある。アルカリ化合物は、例えば、水酸化ナトリウム、水酸化カリウム等であってよい。 For example, the absorbing liquid may include an alkali compound. When the absorbing solution contains an alkali compound, COS or H 2 S derived from COS chemically acts on the alkali compound, and the absorption of COS tends to be promoted. The alkali compound may be, for example, sodium hydroxide, potassium hydroxide and the like.
吸収液におけるアルカリ化合物の含有量は、特に制限されない。アルカリ化合物の含有量は、例えば、５〜４０質量％であってよい。アルカリ化合物の含有量が５質量％以上であれば、ＣＯＳの吸収が促進され易い。一方、アルカリ化合物の含有量が４０質量％以下であれば、吸収液の粘度の低下により、吸収液を操作し易くなる。その結果、吸収液を液体炭化水素油と効率良く接触させ易い。また液液分離（油相及び水相の分離）等の作業効率が向上し易い。同様の理由から、吸収液におけるアルカリ化合物の含有量は、５〜２０質量％であってもよい。 The content of the alkali compound in the absorbing solution is not particularly limited. The content of the alkali compound may be, for example, 5 to 40% by mass. When the content of the alkali compound is 5% by mass or more, COS absorption is easily promoted. On the other hand, when the content of the alkali compound is 40% by mass or less, the viscosity of the absorbing solution is reduced, so that the absorbing solution can be easily operated. As a result, the absorbing liquid is easily brought into contact with the liquid hydrocarbon oil efficiently. In addition, work efficiency such as liquid-liquid separation (separation of an oil phase and an aqueous phase) is easily improved. For the same reason, the content of the alkali compound in the absorbing solution may be 5 to 20% by mass.
以下に、実施例を挙げて本発明を更に具体的に説明するが、本発明は下記の実施例に何ら限定されるものではない。 Hereinafter, the present invention will be described more specifically with reference to examples. However, the present invention is not limited to the examples below.
［液体炭化水素油の調製］
チオシアン酸カリウムに濃硫酸を接触させてＣＯＳを発生させた。このＣＯＳを、ヘキサンに接触させ、ヘキサンに吸収させた。このヘキサンをヘキサンで希釈することにより、ＣＯＳを含有量するヘキサン（液体炭化水素油）を調製した。
[Preparation of liquid hydrocarbon oil]
COS was generated by contacting concentrated sulfuric acid with potassium thiocyanate. This COS was brought into contact with hexane and absorbed into hexane. This hexane was diluted with hexane to prepare hexane (liquid hydrocarbon oil) containing COS.
上記の液体炭化水素油の組成をＧＣ−ＳＣＤによって分析した。ＧＣ−ＳＣＤとは、ガスクロマトグラフ（Ｇａｓ Ｃｈｒｏｍａｔｏｇｒａｐｈ）の検出器として化学発光硫黄検出器（Ｓｕｌｆｕｒ Ｃｈｅｍｉｌｕｍｉｎｅｓｃｅｎｃｅ Ｄｅｔｅｃｔｏｒ）を接続した分析装置である。ＧＣ−ＳＣＤは、以下の条件下で行った。ＧＣ−ＳＣＤによって測定された液体炭化水素油のクロマトグラムを図１に示す。液体炭化水素油中のＣＯＳの含有量は２５７μｇ／ｍｌであった。液体炭化水素油中のＨ２Ｓの含有量は０μｇ／ｍｌであった。 The composition of the above liquid hydrocarbon oil was analyzed by GC-SCD. The GC-SCD is an analyzer connected to a sulfur chemiluminescence detector (Sulfur Chemiluminescence Detector) as a gas chromatograph (Gas Chromatograph) detector. GC-SCD was performed under the following conditions. FIG. 1 shows a chromatogram of the liquid hydrocarbon oil measured by GC-SCD. The content of COS in the liquid hydrocarbon oil was 257 μg / ml. The content of H 2 S in the liquid hydrocarbon oil was 0 μg / ml.
カラム：メチルシリコン系液相（シグマアルドリッチ社製、Ｅｑｕｉｔｙ-１；ＯＶ−１相当、長さ１００ｍ×内径０．２５ｍｍ×膜厚１．０μｍ）
注入口温度：２５０℃（一定）
スプリット比：１００：１
キャリアーガス：水素（流量：２．０ｍｌ／ｍｉｎ）
ＧＣ−ＳＣＤ：（Ａｇｉｌｅｎｔ Ｔｅｃｈｎｏｌｏｇｉｅｓ社製 ＧＣ７８９０Ａ、同社製 （ＳＣＤ）Ａｇｉｌｅｎｔ３５５）
カラム昇温パターン：４０℃で５分間維持した後、５℃／ｍｉｎで昇温し、３２０℃で６１分間維持した。
Column: methyl silicon-based liquid phase (Sigma-Aldrich, Equity-1, OV-1 equivalent, length 100 m × inner diameter 0.25 mm × film thickness 1.0 μm)
Inlet temperature: 250 ° C (constant)
Split ratio: 100: 1
Carrier gas: hydrogen (flow rate: 2.0 ml / min)
GC-SCD: (GC7890A manufactured by Agilent Technologies, (SCD) Agilent355 manufactured by the company)
Column temperature rising pattern: After maintaining at 40 ° C. for 5 minutes, the temperature was raised at 5 ° C./min and maintained at 320 ° C. for 61 minutes.
［ＭＥＡ水溶液の調製］
蒸留水を予めアルゴンガスにて３０分間バブリングして曝気し、調整水を用意した。得られた調整水を、窒素雰囲気下でＭＥＡと混合し、ＭＥＡの含有量が２０質量％であるＭＥＡ水溶液（吸収液）を調製した。
[Preparation of MEA aqueous solution]
Distilled water was previously aerated by bubbling with argon gas for 30 minutes to prepare conditioned water. The obtained conditioned water was mixed with MEA under a nitrogen atmosphere to prepare an MEA aqueous solution (absorbent) having a MEA content of 20% by mass.
［ＤＥＡ水溶液の調製］
蒸留水を予めアルゴンガスにて３０分間バブリングして曝気し、調整水を用意した。得られた調整水を、窒素雰囲気下でＤＥＡと混合し、ＤＥＡの含有量が２０質量％であるＤＥＡ水溶液（吸収液）を調製した。
[Preparation of DEA aqueous solution]
Distilled water was previously aerated by bubbling with argon gas for 30 minutes to prepare conditioned water. The obtained conditioned water was mixed with DEA under a nitrogen atmosphere to prepare a DEA aqueous solution (absorbing solution) having a DEA content of 20% by mass.
［ジイソプロパノールアミン（ＤＩＰＡ）水溶液の調製］
蒸留水を予めアルゴンガスにて３０分間バブリングして曝気し、調整水を用意した。得られた調整水を、窒素雰囲気下でＤＩＰＡと混合し、ＤＩＰＡの含有量２０質量％であるＤＩＰＡ水溶液（吸収液）を調製した。
[Preparation of diisopropanolamine (DIPA) aqueous solution]
Distilled water was previously aerated by bubbling with argon gas for 30 minutes to prepare conditioned water. The obtained conditioned water was mixed with DIPA under a nitrogen atmosphere to prepare a DIPA aqueous solution (absorbent) having a DIPA content of 20% by mass.
［メチルジエタノールアミン（ＭＤＥＡ）水溶液の調製］
蒸留水を予めアルゴンガスにて３０分間バブリングして曝気し、調整水を用意した。得られた調整水を、窒素雰囲気下でＭＤＥＡと混合し、ＭＤＥＡの含有量が２０質量％であるＭＤＥＡ水溶液（吸収液）を調製した。
[Preparation of aqueous solution of methyldiethanolamine (MDEA)]
Distilled water was previously aerated by bubbling with argon gas for 30 minutes to prepare conditioned water. The obtained conditioned water was mixed with MDEA under a nitrogen atmosphere to prepare an MDEA aqueous solution (absorbent) having a MDEA content of 20% by mass.
［実施例１］
以下の吸収実験を行った。なお、大気中の酸素及び二酸化炭素が実験結果に影響することを防止するために、窒素雰囲気下で下記の実験を行った。
[Example 1]
The following absorption experiments were performed. The following experiment was performed under a nitrogen atmosphere to prevent oxygen and carbon dioxide in the atmosphere from affecting the experimental results.
ＣＯＳを含有する上記ヘキサン（液体炭化水素油）２０ｇ、及びＭＥＡ水溶液（吸収液）２０ｇを、５０ｍｌのスクリュー瓶に入れて、スクリュー瓶に蓋をした。このスクリュー瓶を手で振って、スクリュー瓶内の液体炭化水素油及び吸収液を１０分間撹拌した。攪拌後のスクリュー瓶を約１時間静置した。スクリュー瓶内の混合液が油相及び水相に分離されていることを確認した。油相及び水相其々をスクリュー瓶から採取した。 20 g of the above hexane (liquid hydrocarbon oil) containing COS and 20 g of an MEA aqueous solution (absorbing solution) were placed in a 50 ml screw bottle, and the screw bottle was capped. The screw bottle was shaken by hand, and the liquid hydrocarbon oil and the absorbing liquid in the screw bottle were stirred for 10 minutes. The screw bottle after the stirring was allowed to stand for about 1 hour. It was confirmed that the mixture in the screw bottle was separated into an oil phase and an aqueous phase. The oil and water phases were each taken from a screw bottle.
スクリュー瓶から採取された油相試料を、前処理することなく、上記と同様のＧＣ−ＳＣＤで分析した。ＧＣ−ＳＣＤで測定された実施例１の油相試料のクロマトグラムを図２に示す。ＧＣ−ＳＣＤにより、油相試料に残留しているＣＯＳ及びＨ２Ｓを定量した。油相試料中のＣＯＳの含有量を、下記表１に示す。油相試料中のＨ２Ｓの含有量を、下記表１に示す。 The oil phase sample collected from the screw bottle was analyzed by GC-SCD as described above without pretreatment. FIG. 2 shows a chromatogram of the oil phase sample of Example 1 measured by GC-SCD. The GC-SCD, were quantified COS and H 2 S remaining in the oil phase sample. The content of COS in the oil phase sample is shown in Table 1 below. The content of H 2 S in the oil phase sample is shown in Table 1 below.
下記式１によって算出された実施例１の除去率を、下記表１に示す。
除去率（％）＝｛（Ｄ０−Ｄ１）／Ｄ０｝×１００ （１）
式１中、Ｄ０とは、吸収実験前に測定された液体炭化水素油中のＣＯＳの含有量である。つまり、Ｄ０は、２５７μｇ／ｍｌである。Ｄ１とは、吸収実験によって得られた油相試料中のＣＯＳの含有量である。
Table 1 below shows the removal rates of Example 1 calculated by the following Equation 1.
Removal rate (%) = {(D 0 −D 1 ) / D 0 } × 100 (1)
In Equation 1, D 0 is the content of COS in the liquid hydrocarbon oil measured before the absorption experiment. That, D 0 is 257μg / ml. D 1 and is the amount of COS in the oil phase obtained in the sample by absorption experiments.
スクリュー瓶から採取された水相を、減圧乾燥器にて減圧下、４０℃、６時間加熱し、水相中の水分を除去した。水分の除去後に残留した物質をエタノールに溶解して、水相試料を調製した。水相試料をＧＣ−ＭＳで分析した。ＧＣ−ＭＳとは、ガスクロマトグラフ−質量分析（Ｍａｓｓ Ｓｐｅｃｔｒｏｍｅｔｒｙ）である。ＧＣ−ＭＳは、以下の条件下で行った。ＧＣ−ＭＳによって測定された水相試料のクロマトグラムを図６（ａ）及び図６（ｂ）に示す。図６（ａ）及び図６（ｂ）は、其々横軸のスケールが異なるが、同一の水相試料のクロマトグラムである。 The aqueous phase collected from the screw bottle was heated at 40 ° C. for 6 hours under reduced pressure in a vacuum dryer to remove water in the aqueous phase. The substance remaining after the removal of water was dissolved in ethanol to prepare an aqueous phase sample. The aqueous phase sample was analyzed by GC-MS. GC-MS is gas chromatography-mass spectrometry. GC-MS was performed under the following conditions. FIGS. 6A and 6B show the chromatograms of the aqueous phase sample measured by GC-MS. FIGS. 6 (a) and 6 (b) are chromatograms of the same aqueous phase sample, each of which has a different horizontal scale.
カラム：メチルシリコン系液相（シグマアルドリッチ社製、Ｅｑｕｉｔｙ-１；ＯＶ−１相当、長さ１００ｍ×内径０．２５ｍｍ×膜厚１．０μｍ）
注入口温度：２８０℃（一定）
キャリアーガス：ヘリウム（流量：１．５ｍｌ／ｍｉｎ）
ＧＣ−ＭＳ装置：（Ａｇｉｌｅｎｔ Ｔｅｃｈｎｏｌｏｇｉｅｓ社製 ＧＣ６８９０Ｎ、同社製 （ＭＳ）５９７５Ｂ）
イオン化法：電子イオン化（ＥＩ）
カラム昇温パターン：４０℃で５分間維持した後、５℃／ｍｉｎで昇温し、３２０℃で６１分間維持した。
Column: methyl silicon-based liquid phase (Sigma-Aldrich, Equity-1, OV-1 equivalent, length 100 m × inner diameter 0.25 mm × film thickness 1.0 μm)
Inlet temperature: 280 ° C (constant)
Carrier gas: helium (flow rate: 1.5 ml / min)
GC-MS device: (GC6890N manufactured by Agilent Technologies, (MS) 5975B manufactured by Agilent Technologies)
Ionization method: Electron ionization (EI)
Column temperature rising pattern: After maintaining at 40 ° C. for 5 minutes, the temperature was raised at 5 ° C./min and maintained at 320 ° C. for 61 minutes.
ＧＣ−ＭＳに基づき、水相試料中のＨ２Ｓの有無を調べた。もし液体炭化水素油中のＣＯＳがＭＥＡ水溶液に吸収される場合、ＣＯＳの少なくとも一部は分解してＨ２Ｓ及びＣＯ２が生成しているはずである。そして、Ｈ２Ｓ及びＣＯ２は、液体炭化水素油及びＭＥＡ水溶液の混合液における水相に吸収され、水相中においてＨ２ＳはＭＥＡと結合しているはずである。Ｈ２ＳがＭＥＡと結合している場合、ＧＣ−ＭＳ装置の試料導入部が２５０℃以上に加熱されているため、試料導入部においてＨ２ＳがＭＥＡから分離され、検出器ではＨ２Ｓが検出されるはずである。以上の原理に基づき、水相中のＨ２Ｓの有無を判断した。実施例１の水相試料中のＨ２Ｓの有無を、下記表１に示す。 The presence or absence of H 2 S in the aqueous phase sample was examined based on GC-MS. If the COS in the liquid hydrocarbon oil is absorbed into the aqueous MEA solution, at least a portion of the COS must have decomposed to form H 2 S and CO 2 . Then, H 2 S and CO 2 are absorbed by the aqueous phase in the mixture of the liquid hydrocarbon oil and the MEA aqueous solution, and H 2 S should be bonded to the MEA in the aqueous phase. If H 2 S is bonded to MEA, since the sample introducing portion of the GC-MS system is heated above 250 ℃, H 2 S in the sample inlet is separated from the MEA, the detector H 2 S Should be detected. Based on the above principle, the presence or absence of H 2 S in the aqueous phase was determined. The presence or absence of H 2 S in the aqueous phase sample of Example 1 is shown in Table 1 below.
［実施例２］
吸収液として、ＭＥＡ水溶液の代わりに、上記のＤＥＡ水溶液を使用した以外は、実施例１と同様の吸収実験を行った。
[Example 2]
The same absorption experiment as in Example 1 was performed, except that the above-mentioned DEA aqueous solution was used instead of the MEA aqueous solution as the absorbing solution.
［比較例１］
吸収液として、ＭＥＡ水溶液の代わりに、上記のＤＩＰＡ水溶液を使用した以外は、実施例１と同様の吸収実験を行った。
[Comparative Example 1]
The same absorption experiment as in Example 1 was performed, except that the above DIPA aqueous solution was used instead of the MEA aqueous solution as the absorbing solution.
［比較例２］
吸収液として、ＭＥＡ水溶液の代わりに、上記のＭＤＥＡ水溶液を使用した以外は、実施例１と同様の吸収実験を行った。
[Comparative Example 2]
The same absorption experiment as in Example 1 was performed except that the above-mentioned MDEA aqueous solution was used instead of the MEA aqueous solution as the absorbing solution.
実施例２の油相試料のクロマトグラムを図３に示す。比較例１の油相試料のクロマトグラムを図４に示す。比較例２の油相試料のクロマトグラムを図５に示す。実施例２並びに比較例１及び２其々の油相試料中のＣＯＳの含有量を、下記表１に示す。実施例２並び比較例１及び２其々の油相試料中のＨ２Ｓの含有量を、下記表１に示す。 The chromatogram of the oil phase sample of Example 2 is shown in FIG. The chromatogram of the oil phase sample of Comparative Example 1 is shown in FIG. The chromatogram of the oil phase sample of Comparative Example 2 is shown in FIG. Example 2 and Comparative Examples 1 and 2 Table 1 below shows the content of COS in the oil phase samples. The content of H 2 S in the oil phase samples of Example 2 and Comparative Examples 1 and 2 is shown in Table 1 below.
実施例２並びに比較例１及び２其々の除去率を、下記表１に示す。 The removal rates of Example 2 and Comparative Examples 1 and 2 are shown in Table 1 below.
実施例２の水相試料のクロマトグラムを図７に示す。比較例１の水相試料のクロマトグラムを図８に示す。比較例２の水相試料のクロマトグラムを図９に示す。実施例２並び比較例１及び２其々の水相試料中のＨ２Ｓの有無を、下記表１に示す。下記表１において「有」とは、水相試料中にＨ２Ｓが存在していることを意味する。下記表１において「無」とは、水相試料中にＨ２Ｓが存在しないことを意味する。 The chromatogram of the aqueous phase sample of Example 2 is shown in FIG. The chromatogram of the aqueous phase sample of Comparative Example 1 is shown in FIG. FIG. 9 shows a chromatogram of the aqueous phase sample of Comparative Example 2. The presence or absence of H 2 S in the aqueous phase samples of Example 2 and Comparative Examples 1 and 2 is shown in Table 1 below. In Table 1 below, “Yes” means that H 2 S is present in the aqueous phase sample. In Table 1 below, “absent” means that H 2 S does not exist in the aqueous phase sample.
ＧＣ−ＳＣＤを用いた分析の結果、全の実施例及び比較例の油相試料中のＣＯＳの含有量は、吸収実験前の液体炭化水素油中のＣＯＳの含有量（２５７μｇ／ｍｌ）よりも低いことが確認された。つまり、全の実施例及び比較例の吸収実験において、ＣＯＳが液体炭化水素油から除去されていることが確認された。 As a result of the analysis using GC-SCD, the content of COS in the oil phase samples of all Examples and Comparative Examples was higher than the content of COS (257 μg / ml) in the liquid hydrocarbon oil before the absorption experiment. It was confirmed that it was low. That is, in the absorption experiments of all the examples and comparative examples, it was confirmed that COS was removed from the liquid hydrocarbon oil.
全実施例の油相試料中のＣＯＳの含有量は、全比較例のＣＯＳの含有量よりも少ないことが確認された。全実施例の除去率は全比較例の除去よりも高いことが確認された。つまり、実施例１及び２で用いた吸収液は、比較例１及び２の吸収液に比べて、より多量のＣＯＳを液体炭化水素油から除去したことが確認された。 It was confirmed that the content of COS in the oil phase samples of all Examples was lower than the content of COS of all Comparative Examples. It was confirmed that the removal rate of all the examples was higher than that of all the comparative examples. That is, it was confirmed that the absorbent used in Examples 1 and 2 removed a larger amount of COS from the liquid hydrocarbon oil than the absorbents of Comparative Examples 1 and 2.
ＧＣ−ＳＣＤを用いた分析の結果、吸収実験前の液体炭化水素油、及び吸収実験で得られた油相試料のいずれにおいても、Ｈ２Ｓは存在していないことが確認された。 As a result of analysis using GC-SCD, it was confirmed that H 2 S was not present in any of the liquid hydrocarbon oil before the absorption experiment and the oil phase sample obtained in the absorption experiment.
実施例１の水相試料のクロマトグラムにはＨ２Ｓのピークがあることが確認された。一方、実施例２並びに比較例１及び２のクロマトグラムにおいては、明確なＨ２Ｓのピークはなかった。これらの分析結果から、ＭＥＡ水溶液は、液体炭化水素油中の一部のＣＯＳをＨ２Ｓに分解したことが確認された。 It was confirmed that the chromatogram of the aqueous phase sample of Example 1 had an H 2 S peak. On the other hand, in the chromatograms of Example 2 and Comparative Examples 1 and 2, there was no clear H 2 S peak. From these analysis results, it was confirmed that the MEA aqueous solution decomposed part of COS in the liquid hydrocarbon oil into H 2 S.
Claims (2)
前記吸収工程の後、前記吸収液を加熱して前記硫化水素を前記吸収液から放出させる再生工程を更に備え、
前記吸収液が、モノエタノールアミンを１５〜４０質量％含有する水溶液であり、水酸化ナトリウム及び水酸化カリウムからなる群より選ばれる少なくとも１種を更に含有する、
液体炭化水素油中の硫化カルボニルを除去する方法。 The carbonyl sulfide contained in the liquid hydrocarbon oil is decomposed into hydrogen sulfide by bringing the liquid hydrocarbon oil into contact with the absorbing liquid, and the hydrogen sulfide is absorbed into the absorbing liquid. Equipped with an absorption process to remove from hydrogen oil,
After the absorption step, further comprising a regeneration step of heating the absorption liquid to release the hydrogen sulfide from the absorption liquid,
The absorption liquid, Ri aqueous der containing monoethanolamine 15-40 wt%, further contains at least one selected from the group consisting of sodium hydroxide and potassium hydroxide,
A method for removing carbonyl sulfide in a liquid hydrocarbon oil.
請求項１に記載の方法。 The absorption liquid heated in the regeneration step further includes a reuse step of reusing the absorption liquid in the absorption step.
The method of claim 1.
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| US2311342A (en) * | 1941-03-15 | 1943-02-16 | Standard Oil Dev Co | Sulphur removal from hydrocarbons |
| JPS4864002A (en) * | 1971-12-11 | 1973-09-05 | ||
| JPS5527102A (en) * | 1978-07-15 | 1980-02-27 | Osaka Sekiyu Kagaku Kk | Removal of carbonyl sulfide with active alumina |
| US4233141A (en) * | 1979-04-27 | 1980-11-11 | The Ralph M. Parsons Company | Process for removal of carbonyl sulfide in liquified hydrocarbon gases with absorption of acid gases |
| CA1304911C (en) * | 1985-10-28 | 1992-07-14 | Roscoe L. Pearce | Sulfur removal from hydrocarbons |
| MXPA05010039A (en) * | 2003-03-21 | 2005-10-26 | Dow Global Technologies Inc | Improved composition and method for removal of carbonyl sulfide from acid gas containing same. |
| JP4971433B2 (en) * | 2006-05-18 | 2012-07-11 | ビーエーエスエフ ソシエタス・ヨーロピア | Removal of acidic gases from fluid streams with reduced co-absorption of hydrocarbons and oxygen |
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