JPH03157490A - Removal of hydrogen sulfide in crude oil - Google Patents
Removal of hydrogen sulfide in crude oilInfo
- Publication number
- JPH03157490A JPH03157490A JP29497289A JP29497289A JPH03157490A JP H03157490 A JPH03157490 A JP H03157490A JP 29497289 A JP29497289 A JP 29497289A JP 29497289 A JP29497289 A JP 29497289A JP H03157490 A JPH03157490 A JP H03157490A
- Authority
- JP
- Japan
- Prior art keywords
- hydrogen sulfide
- gas
- crude oil
- sent
- separation
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Granted
Links
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 title claims abstract description 92
- 229910000037 hydrogen sulfide Inorganic materials 0.000 title claims abstract description 92
- 239000010779 crude oil Substances 0.000 title claims abstract description 39
- 239000007789 gas Substances 0.000 claims abstract description 46
- 238000000926 separation method Methods 0.000 claims abstract description 22
- 238000010521 absorption reaction Methods 0.000 claims abstract description 14
- 238000000034 method Methods 0.000 claims description 13
- 230000002745 absorbent Effects 0.000 claims description 3
- 239000002250 absorbent Substances 0.000 claims description 3
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 abstract description 16
- 239000007788 liquid Substances 0.000 abstract description 11
- HZAXFHJVJLSVMW-UHFFFAOYSA-N 2-Aminoethan-1-ol Chemical compound NCCO HZAXFHJVJLSVMW-UHFFFAOYSA-N 0.000 abstract description 5
- 230000008929 regeneration Effects 0.000 abstract description 4
- 238000011069 regeneration method Methods 0.000 abstract description 4
- 239000001257 hydrogen Substances 0.000 abstract description 3
- 229910052739 hydrogen Inorganic materials 0.000 abstract description 3
- 125000004435 hydrogen atom Chemical class [H]* 0.000 abstract description 3
- 239000006096 absorbing agent Substances 0.000 abstract 1
- 238000005265 energy consumption Methods 0.000 abstract 1
- 238000004064 recycling Methods 0.000 abstract 1
- 230000001172 regenerating effect Effects 0.000 abstract 1
- VLKZOEOYAKHREP-UHFFFAOYSA-N methyl pentane Natural products CCCCCC VLKZOEOYAKHREP-UHFFFAOYSA-N 0.000 description 15
- NNPPMTNAJDCUHE-UHFFFAOYSA-N isobutane Chemical compound CC(C)C NNPPMTNAJDCUHE-UHFFFAOYSA-N 0.000 description 14
- ATUOYWHBWRKTHZ-UHFFFAOYSA-N Propane Chemical compound CCC ATUOYWHBWRKTHZ-UHFFFAOYSA-N 0.000 description 12
- 238000007796 conventional method Methods 0.000 description 10
- QWTDNUCVQCZILF-UHFFFAOYSA-N isopentane Chemical compound CCC(C)C QWTDNUCVQCZILF-UHFFFAOYSA-N 0.000 description 10
- OFBQJSOFQDEBGM-UHFFFAOYSA-N Pentane Chemical compound CCCCC OFBQJSOFQDEBGM-UHFFFAOYSA-N 0.000 description 7
- 239000001282 iso-butane Substances 0.000 description 7
- 229930195733 hydrocarbon Natural products 0.000 description 6
- 150000002430 hydrocarbons Chemical class 0.000 description 6
- 230000014759 maintenance of location Effects 0.000 description 6
- 239000001294 propane Substances 0.000 description 6
- IJDNQMDRQITEOD-UHFFFAOYSA-N sec-butylidene Natural products CCCC IJDNQMDRQITEOD-UHFFFAOYSA-N 0.000 description 6
- AFABGHUZZDYHJO-UHFFFAOYSA-N dimethyl butane Natural products CCCC(C)C AFABGHUZZDYHJO-UHFFFAOYSA-N 0.000 description 5
- 239000004215 Carbon black (E152) Substances 0.000 description 3
- 239000003345 natural gas Substances 0.000 description 3
- 239000000243 solution Substances 0.000 description 3
- 239000002912 waste gas Substances 0.000 description 3
- 238000010586 diagram Methods 0.000 description 2
- 230000000717 retained effect Effects 0.000 description 2
- GIAFURWZWWWBQT-UHFFFAOYSA-N 2-(2-aminoethoxy)ethanol Chemical compound NCCOCCO GIAFURWZWWWBQT-UHFFFAOYSA-N 0.000 description 1
- OTMSDBZUPAUEDD-UHFFFAOYSA-N Ethane Chemical compound CC OTMSDBZUPAUEDD-UHFFFAOYSA-N 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000005611 electricity Effects 0.000 description 1
- 239000000446 fuel Substances 0.000 description 1
- 238000004519 manufacturing process Methods 0.000 description 1
- 238000012856 packing Methods 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G31/00—Refining of hydrocarbon oils, in the absence of hydrogen, by methods not otherwise provided for
Abstract
Description
【発明の詳細な説明】
〔産業上の利用分野〕
本発明は原油中に含まれる硫化水素を除去する方法に関
する。DETAILED DESCRIPTION OF THE INVENTION [Field of Industrial Application] The present invention relates to a method for removing hydrogen sulfide contained in crude oil.
第２図により、従来のコールドストリッピング法と呼ば
れる原油中の硫化水素を除去する方法について説明する
。A conventional method for removing hydrogen sulfide from crude oil, called the cold stripping method, will be explained with reference to FIG.
硫化水素を含む原油１は硫化水素分離塔２に供給され、
硫化水素分離用ガス３と硫化水素分離塔２の内に設けら
れた棚段又は充てん材中に交流接触し、原油中の硫化水
素は硫化水素分離用ガスによりストリッピングされ原油
中の溶解していた軽質炭化水素ガスと共に硫化水素分離
塔２よりの廃ガス４として排出される。硫化水素分離塔
２の下部は大気圧よりも高くなるため、硫化水素を除去
された原油５は原油タンク６へ送られ、ここで大気圧ま
で脱圧することにより原油タンク６より廃ガス７が排出
され、原油は製品原油８となる。Crude oil 1 containing hydrogen sulfide is supplied to a hydrogen sulfide separation tower 2,
The hydrogen sulfide separation gas 3 and the tray or packing provided in the hydrogen sulfide separation tower 2 are brought into AC contact, and the hydrogen sulfide in the crude oil is stripped by the hydrogen sulfide separation gas and dissolved in the crude oil. It is discharged as waste gas 4 from the hydrogen sulfide separation tower 2 together with the light hydrocarbon gas. Since the pressure at the bottom of the hydrogen sulfide separation tower 2 is higher than atmospheric pressure, the crude oil 5 from which hydrogen sulfide has been removed is sent to the crude oil tank 6, where it is depressurized to atmospheric pressure and waste gas 7 is discharged from the crude oil tank 6. The crude oil becomes product crude oil 8.
従来のコールドストリッピング法においては硫化水素除
去用ガスが消費され、しかも原油中の保持されるプロパ
ン、イソブタン、ノルマルブタン、イソペンタン、ノル
マルペンタン、ヘキサン等の軽質炭化水素が損失すると
いう不具合がある。In the conventional cold stripping method, gas for removing hydrogen sulfide is consumed, and light hydrocarbons such as propane, isobutane, normal butane, isopentane, normal pentane, and hexane retained in the crude oil are lost.
本発明は上記技術水準に鑑み、従来のコールドストリッ
ピング法におけるような不具合のない原油からの硫化水
素の除去方法を提供しようとするものである。In view of the above-mentioned state of the art, the present invention seeks to provide a method for removing hydrogen sulfide from crude oil without the problems encountered in conventional cold stripping methods.
本発明は硫化水素分離塔で原油を硫化水素除去用ガスと
接触させ、硫化水素含有硫化水素除去用ガスを硫化水素
吸収塔で硫化水素吸収剤と接触して硫化水素を吸収除去
し、硫化水素を除去された硫化水素除去用ガスを硫化水
素分離塔に昇圧循環させることを特徴とする原油中の硫
化水素の除去方法である。The present invention involves contacting crude oil with a hydrogen sulfide removal gas in a hydrogen sulfide separation tower, contacting the hydrogen sulfide-containing hydrogen sulfide removal gas with a hydrogen sulfide absorbent in a hydrogen sulfide absorption tower to absorb and remove hydrogen sulfide, and removing hydrogen sulfide. This method of removing hydrogen sulfide from crude oil is characterized by circulating the hydrogen sulfide removal gas from which the hydrogen sulfide has been removed under increased pressure to a hydrogen sulfide separation column.
本発明で使用する硫化水素除去用ガスとしては従来のコ
ールドストリッピング法で使用されているものと同じも
の、例えばメタンを主成分とする天然ガス（Ｎ、、 Ｃ
Ｄ、を含むこともある）が用いられる。また硫化水素吸
収剤としては、これまた−船釣に用いられるモノエタノ
ールアミン水溶液などが使用される。The hydrogen sulfide removal gas used in the present invention is the same as that used in conventional cold stripping methods, such as natural gas whose main component is methane (N, C
D) is used. As the hydrogen sulfide absorbent, an aqueous monoethanolamine solution, which is also used for boat fishing, is used.
硫化水素分離塔より抜き出される硫化水素除去用ガス中
には、硫化水素ガスを多量に含むと同時に、プロパン、
イソブタン、ノルマルブタン、イソペンタン、ノルマル
ペンタン、ヘキサン等の成分を多量に含む。このガス中
の硫化水素ガスをモノエタノールアミン水溶液等の硫化
水素除去用溶液を用いて硫化水素吸収塔において吸収除
去し、ガス循環機にて昇圧し、硫化水素分離塔の下部に
注入する。The hydrogen sulfide removal gas extracted from the hydrogen sulfide separation tower contains a large amount of hydrogen sulfide gas, as well as propane,
Contains large amounts of components such as isobutane, normal butane, isopentane, normal pentane, and hexane. Hydrogen sulfide gas in this gas is absorbed and removed in a hydrogen sulfide absorption tower using a hydrogen sulfide removal solution such as a monoethanolamine aqueous solution, the pressure is increased in a gas circulation machine, and the pressure is injected into the lower part of the hydrogen sulfide separation tower.
従来のコールドストリッピングプロセスにおいて、系外
より導入した天然ガスにて原油をストリッピングする場
合、天然ガスとしては一般にメタン分の比率の高く、他
の炭化水素の比率の少ないガスを用いるため、原油中の
硫化水素と共に、プロパン、イソブタン、ノルマルブタ
ン、イソペンタン、ノルマルペンタン、ヘキサン等の成
分も原油中より多量に除去され、硫化水素分離塔よりの
廃ガスとなって廃山される。In the conventional cold stripping process, when crude oil is stripped using natural gas introduced from outside the system, the natural gas used is generally a gas with a high methane content and a low proportion of other hydrocarbons. Along with the hydrogen sulfide contained therein, components such as propane, isobutane, n-butane, isopentane, n-pentane, and hexane are also removed from the crude oil in large quantities, and the waste gas from the hydrogen sulfide separation tower is discarded.
しかしながら、本発明においては硫化水素分離塔の下部
に注入される循環ガスは、原油の硫化水素のストリッピ
ングガスとしてプロパン、イソブタン、ノルマルブタン
、イソペンタン、ノルマルペンタン、ヘキサン等の成分
を多量に含んでいるので原油中の保持されるプロパン、
イソブタン、ノルマルブタン、イソブタン、ヘキサンの
比率を高めることができる。However, in the present invention, the circulating gas injected into the lower part of the hydrogen sulfide separation tower contains a large amount of components such as propane, isobutane, n-butane, isopentane, n-pentane, hexane, etc. as a stripping gas for hydrogen sulfide in crude oil. Because propane is retained in crude oil,
The ratio of isobutane, normal butane, isobutane, and hexane can be increased.
また、硫化水素除去用ガスを循環して使用するため、系
外よりの硫化水素を除去するためのガスを補給する必要
がない。Furthermore, since the gas for removing hydrogen sulfide is circulated and used, there is no need to replenish gas for removing hydrogen sulfide from outside the system.
〔実施例］ 本発明の一実施例を第１図によって説明する。〔Example] An embodiment of the present invention will be described with reference to FIG.
硫化水素を含む原油１は硫化水素分離塔２において、硫
化水素を除去された硫化水素分離用循環ガス３によりス
トリッピングされ、原油中の硫化水素とメタン分を主体
としたガスはストリッピングと共に硫化水素分離塔２よ
り排ガス４となり、排出される。この硫化水素を多量に
含むガス中の硫化水素は硫化水素吸収塔９において硫化
水素吸収液１０にて吸収される。Crude oil 1 containing hydrogen sulfide is stripped in a hydrogen sulfide separation tower 2 using hydrogen sulfide separation circulating gas 3 from which hydrogen sulfide has been removed, and the gas mainly consisting of hydrogen sulfide and methane in the crude oil is stripped and sulfurized. Exhaust gas 4 is generated from the hydrogen separation tower 2 and is discharged. Hydrogen sulfide in this gas containing a large amount of hydrogen sulfide is absorbed by a hydrogen sulfide absorption liquid 10 in a hydrogen sulfide absorption tower 9 .
硫化水素吸収液としてはモノエタノールアミン、モノメ
チルジェタノールアミン、ジェタノールアミン、ジグリ
コールアミン、スルフィツールなどの溶液を用いること
ができる。As the hydrogen sulfide absorption liquid, solutions of monoethanolamine, monomethylgetanolamine, jetanolamine, diglycolamine, sulfitol, etc. can be used.
硫化水素を吸収した吸収液１１は、吸収液送出ポンプ１
２により硫化水素吸収液再生装置１４へ送られ、硫化水
素１５を除かれ硫化水素吸収塔９へと送られる。The absorption liquid 11 that has absorbed hydrogen sulfide is transferred to the absorption liquid delivery pump 1
2, the hydrogen sulfide absorption liquid is sent to the hydrogen sulfide absorption liquid regeneration device 14, where the hydrogen sulfide 15 is removed, and sent to the hydrogen sulfide absorption tower 9.
硫化水素を除去されたガス１６はガス循環機１７により
昇圧され硫化水素分離塔２の下部へ送られる。供給原油
１中に含まれていたメタン分を主体としたガスは系内で
余剰となり、硫化水素を除去された余剰ガス１８として
系外へ送られる。この余剰ガス１８より硫化水素を除去
された炭化水素ガスが回収される。The gas 16 from which hydrogen sulfide has been removed is pressurized by a gas circulator 17 and sent to the lower part of the hydrogen sulfide separation column 2. Gas mainly composed of methane contained in the supplied crude oil 1 becomes surplus within the system, and is sent to the outside of the system as surplus gas 18 from which hydrogen sulfide has been removed. Hydrocarbon gas from which hydrogen sulfide has been removed is recovered from this surplus gas 18.
硫化水素を除去された原油５は原油タンク６にて大気圧
まで脱圧７され、原油の蒸気圧を下げられて、製品原油
８となる。The crude oil 5 from which hydrogen sulfide has been removed is depressurized 7 to atmospheric pressure in a crude oil tank 6, and the vapor pressure of the crude oil is lowered to become a product crude oil 8.
以下、本発明方法と従来の比較を、第１表、第２表によ
って説明する。A comparison between the method of the present invention and the conventional method will be explained below with reference to Tables 1 and 2.
第１表に示す操作条件において、本発明は製品原油中の
硫化水素の比率をほぼ同一（５０重量ｐｐｍ以下）に保
ちながら従来の方法と比較した結果、第２表に示すよう
に、本発明法ではエタン保持率が従来法の１４．５２重
量％より６４．９４重量％に、プロパン保持率が従来法
の４１．６９重量％より８６．５３重量％に、イソブタ
ン保持率が従来法の６８．１０重量％より９３．８２重
量％に、ノルマルブタン保持率が従来法の７７．７１重
量％より９５．６４重量％に、イソペンタン保持率が従
来法の９０．８２重量％より９８．２４重量％に、従来
法のノルマルペンタン保持率が９３．４１重量％より９
８．６６重量％にそれぞれ高めることができる。この結
果として供給原油に帯する製品原油の比率は、従来法が
９８．４３重量％であるのに対し、本発明では９９．４
１％に向上する。さらに本発明は７３６Ｎｍ３／ｕの硫
化水素を除去された炭化水素ガスを得ることができる。Under the operating conditions shown in Table 1, the present invention was compared with the conventional method while keeping the hydrogen sulfide ratio in the product crude oil almost the same (50 ppm by weight or less).As shown in Table 2, the present invention In this method, the ethane retention rate was increased to 64.94% by weight from 14.52% by weight in the conventional method, the propane retention rate was increased to 86.53% by weight from 41.69% by weight in the conventional method, and the isobutane retention rate was increased to 68% by weight in the conventional method. .10% by weight to 93.82% by weight, normal butane retention rate to 95.64% by weight from 77.71% by weight in the conventional method, and isopentane retention rate to 98.24% by weight compared to 90.82% by weight in the conventional method. %, the normal pentane retention rate of the conventional method was 93.41% by weight.
It can be increased to 8.66% by weight, respectively. As a result, the ratio of product crude oil in the supplied crude oil is 98.43% by weight in the conventional method, whereas in the present invention the ratio of product crude oil is 99.4% by weight.
Improved to 1%. Furthermore, the present invention can obtain 736 Nm3/u of hydrocarbon gas from which hydrogen sulfide has been removed.
ユーティリティに関しては、従来の方法が４３５０ Ｎ
ｍ３／Ｈ硫化水素分離用ガスを消費するのに比べ、本発
明は硫化水素吸収液再生用リボクラ−燃料として２９０
Ｎｍａ／Ｈのガスを消費するのと、ガス循環機及びポ
ンプとして１５０ｋＷＨ／）Ｉの電力を消費するのみで
ある。Regarding utilities, the traditional method is 4350 N
Compared to consuming m3/H hydrogen sulfide separation gas, the present invention consumes 290 m3/H gas as a regeneration fuel for hydrogen sulfide absorption liquid regeneration.
It consumes only Nma/H of gas and 150kWH/)I of electricity as a gas circulator and pump.
本発明によれば原油からの硫化水素除去用ガスを系外か
ら補給することなく操業することができ、かつ原油中に
含まれる炭化水素を有効に回収することができる。According to the present invention, it is possible to operate without supplying gas for removing hydrogen sulfide from crude oil from outside the system, and to effectively recover hydrocarbons contained in crude oil.
第１図は本発明の一実施例を説明するための概略図、第
２図は従来の原油から硫化水素をコールトス） ＋Ｊフ
ッピング法よって除去する態様を説明するための概略図
である。FIG. 1 is a schematic diagram for explaining an embodiment of the present invention, and FIG. 2 is a schematic diagram for explaining a mode in which hydrogen sulfide is removed from crude oil by the conventional COLT+J flapping method.
Claims (1)
、硫化水素含有硫化水素除去用ガスを硫化水素吸収塔で
硫化水素吸収剤と接触して硫化水素を吸収除去し、硫化
水素を除去された硫化水素除去用ガスを硫化水素分離塔
に昇圧循環させることを特徴とする原油中の硫化水素の
除去方法。The crude oil is brought into contact with a hydrogen sulfide removal gas in a hydrogen sulfide separation tower, and the hydrogen sulfide-containing hydrogen sulfide removal gas is brought into contact with a hydrogen sulfide absorbent in a hydrogen sulfide absorption tower to absorb and remove hydrogen sulfide. A method for removing hydrogen sulfide from crude oil, which comprises circulating a hydrogen sulfide removal gas under pressure to a hydrogen sulfide separation column.
Priority Applications (3)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| JP29497289A JPH0765053B2 (en) | 1989-11-15 | 1989-11-15 | Method for removing hydrogen sulfide from crude oil |
| EP19900250274 EP0432858B1 (en) | 1989-11-15 | 1990-11-02 | Process for removing hydrogen sulfide from crude petroleum |
| DE1990632972 DE69032972T2 (en) | 1989-11-15 | 1990-11-02 | Process for removing hydrogen sulfide from crude oil |
Applications Claiming Priority (1)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| JP29497289A JPH0765053B2 (en) | 1989-11-15 | 1989-11-15 | Method for removing hydrogen sulfide from crude oil |
Publications (2)
| Publication Number | Publication Date |
|---|---|
| JPH03157490A true JPH03157490A (en) | 1991-07-05 |
| JPH0765053B2 JPH0765053B2 (en) | 1995-07-12 |
Family
ID=17814689
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| JP29497289A Expired - Fee Related JPH0765053B2 (en) | 1989-11-15 | 1989-11-15 | Method for removing hydrogen sulfide from crude oil |
Country Status (3)
| Country | Link |
|---|---|
| EP (1) | EP0432858B1 (en) |
| JP (1) | JPH0765053B2 (en) |
| DE (1) | DE69032972T2 (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| JP2013533371A (en) * | 2010-08-09 | 2013-08-22 | エイチ アール ディー コーポレーション | Crude oil desulfurization |
Families Citing this family (14)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB2317617A (en) * | 1996-09-28 | 1998-04-01 | Capcis Ltd | Removing sulphur compounds from liquid hydrocarbons |
| US9988580B2 (en) | 2014-04-18 | 2018-06-05 | Amperage Energy Inc. | System and method for removing hydrogen sulfide from oilfield effluents |
| RU2578155C1 (en) * | 2015-01-29 | 2016-03-20 | Открытое акционерное общество "Татнефть" имени В.Д. Шашина | Installation for treatment of oil containing hydrogen sulphide |
| RU2586157C1 (en) * | 2015-03-11 | 2016-06-10 | Открытое акционерное общество "Татнефть" имени В.Д. Шашина | Method of preparing oil containing hydrogen sulphide |
| US10550337B2 (en) | 2017-08-01 | 2020-02-04 | GAPS Technology, LLC. | Chemical compositions and methods for remediating hydrogen sulfide and other contaminants in hydrocarbon based liquids and aqueous solutions without the formation of precipitates or scale |
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| US11286433B2 (en) | 2017-08-01 | 2022-03-29 | Gaps Technology, Llc | Compositions and methods for remediating hydrogen sulfide in hydrocarbon based liquids |
| WO2019036731A2 (en) | 2017-08-01 | 2019-02-21 | Gaps Technology, Llc | Chemical solution and methods of using same for remediating hydrogen sulfide and other contaminants in petroleum based and other liquids |
| US11512258B2 (en) | 2017-08-01 | 2022-11-29 | GAPS Technology, LLC. | Chemical compositions and methods of using same for remediating low to moderate amounts of sulfur-containing compositions and other contaminants in liquids |
| RU2664652C1 (en) * | 2018-02-06 | 2018-08-21 | Открытое акционерное общество "Славнефть-Ярославнефтеоргсинтез" (ОАО "Славнефть-ЯНОС") | Method for purification of fuel components from sulfur circulating oils and oil factions |
| US10913911B1 (en) | 2019-09-20 | 2021-02-09 | Gaps Technology Llc | Chemical compositions and treatment systems and treatment methods using same for remediating H2S and other contaminants in gasses |
| US11549064B2 (en) | 2019-09-20 | 2023-01-10 | Gaps Technology, Llc | Chemical compositions and treatment systems and treatment methods using same for remediating H2S and other contaminants in fluids, including liquids,gasses and mixtures thereof |
| AU2022269010A1 (en) | 2021-05-07 | 2023-06-22 | Gaps Technology, Llc | Hydrocarbon liquid based chemical compositions and treatment methods using same for remediating h2s and other contaminants in fluids and mixtures of contaminated fluids |
| US11813551B1 (en) * | 2021-11-22 | 2023-11-14 | Viro Petroleum & Energy, LLC | Hydrogen sulfide mitigation methods and systems |
Family Cites Families (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US2757127A (en) * | 1952-11-18 | 1956-07-31 | British Petroleum Co | Stripping hydrogen sulphide from hydrofined petroleum hydrocarbons with an inert gas |
| DE3427134A1 (en) * | 1984-07-24 | 1986-02-06 | Basf Ag, 6700 Ludwigshafen | METHOD FOR REMOVING CO (DOWN ARROW) 2 (DOWN ARROW) AND / OR H (DOWN ARROW) 2 (DOWN ARROW) S FROM GASES |
-
1989
- 1989-11-15 JP JP29497289A patent/JPH0765053B2/en not_active Expired - Fee Related
-
1990
- 1990-11-02 DE DE1990632972 patent/DE69032972T2/en not_active Expired - Fee Related
- 1990-11-02 EP EP19900250274 patent/EP0432858B1/en not_active Expired - Lifetime
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| JP2013533371A (en) * | 2010-08-09 | 2013-08-22 | エイチ アール ディー コーポレーション | Crude oil desulfurization |
| US8845885B2 (en) | 2010-08-09 | 2014-09-30 | H R D Corporation | Crude oil desulfurization |
Also Published As
| Publication number | Publication date |
|---|---|
| EP0432858B1 (en) | 1999-03-03 |
| EP0432858A1 (en) | 1991-06-19 |
| JPH0765053B2 (en) | 1995-07-12 |
| DE69032972T2 (en) | 1999-07-08 |
| DE69032972D1 (en) | 1999-04-08 |
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