EP2352567A1 - Mercury removal process - Google Patents
Mercury removal processInfo
- Publication number
- EP2352567A1 EP2352567A1 EP09793119A EP09793119A EP2352567A1 EP 2352567 A1 EP2352567 A1 EP 2352567A1 EP 09793119 A EP09793119 A EP 09793119A EP 09793119 A EP09793119 A EP 09793119A EP 2352567 A1 EP2352567 A1 EP 2352567A1
- Authority
- EP
- European Patent Office
- Prior art keywords
- liquid hydrocarbon
- stream
- hydrocarbon stream
- water
- accordance
- 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.)
- Withdrawn
Links
- 238000000034 method Methods 0.000 title claims abstract description 20
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 title abstract description 28
- 229910052753 mercury Inorganic materials 0.000 title description 26
- 229930195733 hydrocarbon Natural products 0.000 claims abstract description 57
- 150000002430 hydrocarbons Chemical class 0.000 claims abstract description 57
- 239000004215 Carbon black (E152) Substances 0.000 claims abstract description 54
- 239000007788 liquid Substances 0.000 claims abstract description 50
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 38
- 239000007800 oxidant agent Substances 0.000 claims abstract description 18
- 239000002351 wastewater Substances 0.000 claims abstract description 8
- 238000006243 chemical reaction Methods 0.000 claims abstract description 5
- 239000010779 crude oil Substances 0.000 claims description 23
- SUKJFIGYRHOWBL-UHFFFAOYSA-N sodium hypochlorite Chemical group [Na+].Cl[O-] SUKJFIGYRHOWBL-UHFFFAOYSA-N 0.000 claims description 7
- 239000005708 Sodium hypochlorite Substances 0.000 claims description 5
- 230000008014 freezing Effects 0.000 claims description 4
- 238000007710 freezing Methods 0.000 claims description 4
- 230000003247 decreasing effect Effects 0.000 abstract 1
- DIOQZVSQGTUSAI-UHFFFAOYSA-N decane Chemical compound CCCCCCCCCC DIOQZVSQGTUSAI-UHFFFAOYSA-N 0.000 description 14
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 12
- 239000007844 bleaching agent Substances 0.000 description 9
- 239000000243 solution Substances 0.000 description 9
- 239000008346 aqueous phase Substances 0.000 description 6
- 239000008367 deionised water Substances 0.000 description 4
- 229910021641 deionized water Inorganic materials 0.000 description 4
- 239000003638 chemical reducing agent Substances 0.000 description 3
- 230000000694 effects Effects 0.000 description 3
- 239000010410 layer Substances 0.000 description 3
- 239000000203 mixture Substances 0.000 description 3
- 238000000197 pyrolysis Methods 0.000 description 3
- 238000006722 reduction reaction Methods 0.000 description 3
- 238000000926 separation method Methods 0.000 description 3
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 2
- 229910019093 NaOCl Inorganic materials 0.000 description 2
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 2
- 238000010936 aqueous wash Methods 0.000 description 2
- 238000011143 downstream manufacturing Methods 0.000 description 2
- 239000012071 phase Substances 0.000 description 2
- 238000012546 transfer Methods 0.000 description 2
- TXUICONDJPYNPY-UHFFFAOYSA-N (1,10,13-trimethyl-3-oxo-4,5,6,7,8,9,11,12,14,15,16,17-dodecahydrocyclopenta[a]phenanthren-17-yl) heptanoate Chemical compound C1CC2CC(=O)C=C(C)C2(C)C2C1C1CCC(OC(=O)CCCCCC)C1(C)CC2 TXUICONDJPYNPY-UHFFFAOYSA-N 0.000 description 1
- 229920002274 Nalgene Polymers 0.000 description 1
- 229910021626 Tin(II) chloride Inorganic materials 0.000 description 1
- 238000010521 absorption reaction Methods 0.000 description 1
- 239000003153 chemical reaction reagent Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 238000010790 dilution Methods 0.000 description 1
- 239000012895 dilution Substances 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 239000011521 glass Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 239000002343 natural gas well Substances 0.000 description 1
- 239000012044 organic layer Substances 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- 230000000717 retained effect Effects 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- 238000000638 solvent extraction Methods 0.000 description 1
- 239000001119 stannous chloride Substances 0.000 description 1
- 235000011150 stannous chloride Nutrition 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
Classifications
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
- B01D—SEPARATION
- B01D11/00—Solvent extraction
- B01D11/04—Solvent extraction of solutions which are liquid
- B01D11/0492—Applications, solvents used
-
- 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
- C10G17/00—Refining of hydrocarbon oils in the absence of hydrogen, with acids, acid-forming compounds or acid-containing liquids, e.g. acid sludge
- C10G17/02—Refining of hydrocarbon oils in the absence of hydrogen, with acids, acid-forming compounds or acid-containing liquids, e.g. acid sludge with acids or acid-containing liquids, e.g. acid sludge
- C10G17/04—Liquid-liquid treatment forming two immiscible phases
- C10G17/07—Liquid-liquid treatment forming two immiscible phases using halogen acids or oxyacids of halogen
-
- 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
- C10G27/00—Refining of hydrocarbon oils in the absence of hydrogen, by oxidation
-
- 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
- C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
- C10G2300/10—Feedstock materials
- C10G2300/1033—Oil well production fluids
-
- 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
- C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
- C10G2300/20—Characteristics of the feedstock or the products
- C10G2300/201—Impurities
- C10G2300/205—Metal content
Definitions
- the present invention relates to a process for the removal of mercury from crude oil.
- this invention relates to a process for the removal of mercury from crude oil using water and an oxidizing agent.
- a process including the following: a) contacting a liquid hydrocarbon stream comprising liquid hydrocarbons and Hg(O) with a water stream consisting essentially of water and an oxidizing agent for conversion of at least a portion of the Hg(O) to Hg(II); b) extracting at least a portion of the Hg(II) from the liquid hydrocarbon stream into the water stream, thereby forming a treated liquid hydrocarbon stream containing less total Hg than the liquid hydrocarbon stream and a waste water stream comprising water and Hg(II); and c) separating the treated liquid hydrocarbon stream from the waste water stream.
- FIGURE 1 is a bar graph showing the mass balance of Hg between the hydrocarbon and aqueous phases for variously treated samples of a crude oil.
- FIGURE 2 is a bar graph showing the mass balance of Hg between the hydrocarbon and aqueous phases for variously treated samples of a crude oil.
- FIGURE 3 is a bar graph showing the mass balance of Hg between the hydrocarbon and aqueous phases for variously treated samples of a crude oil.
- the liquid hydrocarbon stream of this invention can be any liquid hydrocarbon stream which comprises liquid hydrocarbons and mercury in the 0 valence state (Hg (O)).
- the liquid hydrocarbon stream will be a crude oil stream or a condensate stream from a natural gas well.
- the liquid hydrocarbon stream comprises, consists of, or consists essentially of a crude oil containing Hg(O).
- the liquid hydrocarbon stream typically comprises at least about 10 ppb (parts per billion) Hg(O), and more particularly comprises at least about 200 ppb Hg (0).
- the liquid hydrocarbon stream is contacted with a water stream consisting essentially of water and an oxidizing agent for conversion of at least a portion of the Hg(O) to mercury in a +2 valence state (Hg(II)).
- the oxidizing agent can be any chemical or chemical compound capable of oxidizing Hg(O) to Hg(II).
- the oxidizing agent can be sodium hypochlorite.
- the water stream preferably does not contain any component(s) in sufficient quantities such that such component(s) materially affect the ability of the oxidizing agent to oxidize the Hg(O) to Hg(II) or materially affect the ability of the water to extract the Hg(II) from the liquid hydrocarbon stream.
- the oxidizing agent is present in the water stream preferably in an amount such that the molar ratio of the oxidizing agent to the Hg(O) present in liquid hydrocarbon stream is at least about 1 :1, more preferably at least about 7:1, and most preferably at least about 143 : 1.
- the contacting of the liquid hydrocarbon stream with the water stream is preferably at a temperature at least above the freezing points of the liquid hydrocarbon stream and the water stream, more preferably at a temperature at least above the freezing points of the liquid hydrocarbon stream and the water stream and below about 100 0 C, and most preferably at a temperature at least above about 2O 0 C and below about 7O 0 C.
- At least a portion of the Hg(II) is then extracted from the liquid hydrocarbon stream into the water stream, thereby forming a treated liquid hydrocarbon stream containing less Hg than the liquid hydrocarbon stream and a waste water stream comprising water and Hg(II).
- the treated liquid hydrocarbon stream is then separated from the waste water stream by any suitable means.
- the treated liquid hydrocarbon stream preferably contains less than about 50 wt. %, more preferably less than about 20 wt. %, and most preferably less than about 1 wt. %, of the Hg contained in the liquid hydrocarbon stream.
- Table 1 shows that compared to the first bottle with no aqueous wash, there was substantially more mercury removed from the hydrocarbon phase upon the addition of an oxidizing agent (bleach) to the aqueous wash.
- Example 2 Reagent grade decane, in the amounts shown in Table 2, was spiked with approximately
- the optimal mole ratio of mercury to NaOCl in the decane/Bleach solution mix is at least about 1:7.
- Figures 1 - 3 are plots of the mass balance of mercury for samples 1-4 for crude oils A, B and C.
- the black bars in the graph represent the total mercury in ng of the analyzed hydrocarbon phase (or crude oil sample) and the grey bars (to the right of the black bars, if visible) represent the total mercury in ng of the analyzed aqueous phase. Errors due to loss of mass to a rag layer or dilution during centrifuge balancing were small and did not influence the conclusions drawn from the data.
- Example 4 A sample of a crude oil was heated beyond the wax point to obtain a representative sample. To four glass bottles, the following was added: 1) 40 g crude oil only, 2) 40 g crude oil and 4 g deionized water, 3) 40 g crude oil and 4 g 5.6-6.0% sodium hypochlorite (bleach) solution, and 4) 40 g crude oil and 4 g 50% ethylene glycol in water solution. The four samples were shaken for 2 minutes.
Landscapes
- Chemical & Material Sciences (AREA)
- Oil, Petroleum & Natural Gas (AREA)
- Chemical Kinetics & Catalysis (AREA)
- Engineering & Computer Science (AREA)
- General Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
Abstract
A process is disclosed for decreasing the level of elemental mercury contained in a liquid hydrocarbon stream by a) contacting the liquid hydrocarbon stream with a water stream containing an oxidizing agent for conversion of at least a portion of the Hg(0) to Hg(II); b) extracting at least a portion of the Hg(II) from the liquid hydrocarbon stream into the water stream, thereby forming a treated liquid hydrocarbon stream and a waste water stream containing water and Hg(II); and c) separating the treated liquid hydrocarbon stream from the waste water stream.
Description
MERCURY REMOVAL PROCESS
FIELD OF THE INVENTION
The present invention relates to a process for the removal of mercury from crude oil. In another aspect, this invention relates to a process for the removal of mercury from crude oil using water and an oxidizing agent.
BACKGROUND OF THE INVENTION
Since the presence of mercury in crude oil can cause problems with downstream processing units, as well as health and environmental concerns, there is an incentive to remove mercury from crude oil.
Therefore, development of an improved process for effectively removing mercury from crude oil before downstream processing into products would be a significant contribution to the art.
BRIEF SUMMARY OF THE INVENTION In accordance with the present invention, a process is provided including the following: a) contacting a liquid hydrocarbon stream comprising liquid hydrocarbons and Hg(O) with a water stream consisting essentially of water and an oxidizing agent for conversion of at least a portion of the Hg(O) to Hg(II); b) extracting at least a portion of the Hg(II) from the liquid hydrocarbon stream into the water stream, thereby forming a treated liquid hydrocarbon stream containing less total Hg than the liquid hydrocarbon stream and a waste water stream comprising water and Hg(II); and c) separating the treated liquid hydrocarbon stream from the waste water stream.
BRIEF DESCRIPTION OF THE FIGURES
FIGURE 1 is a bar graph showing the mass balance of Hg between the hydrocarbon and aqueous phases for variously treated samples of a crude oil.
FIGURE 2 is a bar graph showing the mass balance of Hg between the hydrocarbon and aqueous phases for variously treated samples of a crude oil.
FIGURE 3 is a bar graph showing the mass balance of Hg between the hydrocarbon and aqueous phases for variously treated samples of a crude oil.
DETAILED DESCRIPTION OF THE INVENTION The liquid hydrocarbon stream of this invention can be any liquid hydrocarbon stream which comprises liquid hydrocarbons and mercury in the 0 valence state (Hg (O)). Most typically, the liquid hydrocarbon stream will be a crude oil stream or a condensate stream from a natural gas well. Most typically the liquid hydrocarbon stream comprises, consists of, or consists essentially of a crude oil containing Hg(O). The liquid hydrocarbon stream typically comprises at least about 10 ppb (parts per billion) Hg(O), and more particularly comprises at least about 200 ppb Hg (0).
The liquid hydrocarbon stream is contacted with a water stream consisting essentially of water and an oxidizing agent for conversion of at least a portion of the Hg(O) to mercury in a +2 valence state (Hg(II)). The oxidizing agent can be any chemical or chemical compound capable of oxidizing Hg(O) to Hg(II). The oxidizing agent can be sodium hypochlorite. The water stream preferably does not contain any component(s) in sufficient quantities such that such
component(s) materially affect the ability of the oxidizing agent to oxidize the Hg(O) to Hg(II) or materially affect the ability of the water to extract the Hg(II) from the liquid hydrocarbon stream. The oxidizing agent is present in the water stream preferably in an amount such that the molar ratio of the oxidizing agent to the Hg(O) present in liquid hydrocarbon stream is at least about 1 :1, more preferably at least about 7:1, and most preferably at least about 143 : 1.
The contacting of the liquid hydrocarbon stream with the water stream is preferably at a temperature at least above the freezing points of the liquid hydrocarbon stream and the water stream, more preferably at a temperature at least above the freezing points of the liquid hydrocarbon stream and the water stream and below about 1000C, and most preferably at a temperature at least above about 2O0C and below about 7O0C.
At least a portion of the Hg(II) is then extracted from the liquid hydrocarbon stream into the water stream, thereby forming a treated liquid hydrocarbon stream containing less Hg than the liquid hydrocarbon stream and a waste water stream comprising water and Hg(II). The treated liquid hydrocarbon stream is then separated from the waste water stream by any suitable means.
The treated liquid hydrocarbon stream preferably contains less than about 50 wt. %, more preferably less than about 20 wt. %, and most preferably less than about 1 wt. %, of the Hg contained in the liquid hydrocarbon stream.
The following examples are provided to further illustrate this invention and are not to be considered as unduly limiting the scope of this invention.
EXAMPLES Example 1
To approximately 80 rnL of decane, approximately 1 gram of Hg(O) was added. The mixture stirred for several days and the mercury spiked decane was decanted. Approximately 10 g of the spiked decane mixture was added to each of five 30 mL Nalgene® bottles. To the first bottle, nothing was added; to the second bottle, approximately 1O g of deionized water was added; to the third bottle, approximately 1O g of 5.6-6.0% bleach solution was added; to the fourth bottle, approximately 1O g of 5.6-6.0% bleach solution and 0.5 g of 4% hydrochloric acid solution was added; and to the fifth bottle, approximately 1O g of 4.6% sodium chloride solution was added.
All 5 bottles were shaken on a mechanical shaker for 30 minutes. A sample of the aqueous layer was removed via transfer pipette from bottles 2-5 for mercury analysis using the OhioLumex Cold Vapor Atomic Absorption Spectrometer (CVAA) coupled with the RP-91 attachment which utilizes chemical reduction of mercury via chemical reaction with stannous chloride. The organic layer (decane) was analyzed with the OhioLumex CVAA Spectrometer coupled with pyro lysis.
TABLE 1
Partitioning of total mercury between decane and aqueous phases
Table 1 shows that compared to the first bottle with no aqueous wash, there was substantially more mercury removed from the hydrocarbon phase upon the addition of an oxidizing agent (bleach) to the aqueous wash. Example 2 Reagent grade decane, in the amounts shown in Table 2, was spiked with approximately
1.1 ppm of Hg(O) to which was added various quantities of 6 wt. % sodium hypochlorite solution and deionized water in the amounts shown in Table 2. The experiments were performed using the procedure outlined above in Example 1.
TABLE 2
Assessing the minimum bleach needed to affect mercury removal
* ~6 wt. % stock NaOCl SoIn.
As can be seen from Table 2, the optimal mole ratio of mercury to NaOCl in the decane/Bleach solution mix is at least about 1:7. Example 3
Samples of three different crude oils (designated as A, B and C) were heated beyond the wax point to obtain representative samples. For each crude oil, four samples of approximately 30 g each were prepared. To three of the four samples, the following bottles were prepared:
1) crude oil only,
2) crude oil and 3 g deionized water, and
3) crude oil and 3 g of 5.6% to 6.0% sodium hypochlorite solution. The fourth sample was capped and retained while the first three samples were shaken for
2 minutes. The three shaken samples were centrifuged at 70 degrees C and 3500 RPM for 20 minutes to effect the separation. All hydrocarbon samples were analyzed for mercury using the
OhioLumex CVAA coupled with pyro lysis. All aqueous samples were analyzed for mercury using the OhioLumex CVAA Spectrometer coupled with the RP-91 chemical reduction attachment.
Figures 1 - 3 are plots of the mass balance of mercury for samples 1-4 for crude oils A, B and C. The black bars in the graph represent the total mercury in ng of the analyzed hydrocarbon phase (or crude oil sample) and the grey bars (to the right of the black bars, if visible) represent the total mercury in ng of the analyzed aqueous phase. Errors due to loss of mass to a rag layer or dilution during centrifuge balancing were small and did not influence the conclusions drawn from the data. It is clear that substantially more mercury was removed by the centrifuge separation for the bleach washed crude samples (the number 3 samples) as compared to the other samples, and the transfer of the mercury to the aqueous phase is evidenced by the increase in mercury concentration in the aqueous layer, as is depicted in the Figures. Example 4 A sample of a crude oil was heated beyond the wax point to obtain a representative sample. To four glass bottles, the following was added: 1) 40 g crude oil only, 2) 40 g crude oil and 4 g deionized water, 3) 40 g crude oil and 4 g 5.6-6.0% sodium hypochlorite (bleach) solution, and 4) 40 g crude oil and 4 g 50% ethylene glycol in water solution. The four samples were shaken for 2 minutes. The four shaken samples were centrifuged at 90 degrees C and 3500 RPM for 20 minutes to effect the separation. All hydrocarbon samples and the sample of ethylene glycol/water were analyzed for mercury using the OhioLumex CVAA coupled with
pyro lysis. All aqueous samples were analyzed for mercury using the OhioLumex CVAA Spectrometer coupled with the RP-91 chemical reduction attachment. Results are shown in Table 3 below, and show that the addition of bleach had a significant effect on Hg removal from the crude as compared to the use of ethylene glycol or DI water to wash the crude.
TABLE 3
Avg . Hg in Crude Avg . Hg in Aqueous (ng) (ng) > Hg in Crud /o Hg in Aqueous
Control 22663 0 100% 0%
Ethylene Glycol 21384 64 100% 0%
DI Water 22490 20 100% 0%
Bleach 5868 13683 30% 70%
While this invention has been described in detail for the purpose of illustration, it should not be construed as limited thereby but intended to cover all changes and modifications within the spirit and scope thereof.
Claims
1. A process comprising: a) contacting a liquid hydrocarbon stream comprising liquid hydrocarbons and Hg(O) with a water stream consisting essentially of water and an oxidizing agent for conversion of at least a portion of said Hg(O) to Hg(II); b) extracting at least a portion of said Hg(II) from said liquid hydrocarbon stream into said water stream, thereby forming a treated liquid hydrocarbon stream containing less Hg than said liquid hydrocarbon stream and a waste water stream comprising water and Hg(II); and c) separating said treated liquid hydrocarbon stream from said waste water stream.
2. A process in accordance with claim 1 wherein said liquid hydrocarbon stream comprises crude oil and Hg (0).
3. A process in accordance with claim 1 wherein said oxidizing agent is sodium hypochlorite.
4. A process in accordance with claim 1 wherein said oxidizing agent is present in said water stream in an amount such that the molar ratio of said oxidizing agent to said Hg (0) present in said liquid hydrocarbon stream is at least about 1 :1.
5. A process in accordance with claim 1 wherein said oxidizing agent is present in said water stream in an amount such that the molar ratio of said oxidizing agent to said Hg(O) present in said liquid hydrocarbon stream is at least about 7:1.
6. A process in accordance with claim 1 wherein said oxidizing agent is present in said water stream in an amount such that the molar ratio of said oxidizing agent to said Hg(O) present in said liquid hydrocarbon stream is at least about 143:1.
7. A process in accordance with claim 1 wherein said contacting of said liquid hydrocarbon stream with said water stream is at a temperature at least above the freezing points of said liquid hydrocarbon stream and said water stream.
8. A process in accordance with claim 1 wherein said contacting of said liquid hydrocarbon stream with said water stream is at a temperature at least above the freezing points of said liquid hydrocarbon stream and said water stream and below about 1000C.
9. A process in accordance with claim 1 wherein said contacting of said liquid hydrocarbon stream with said water stream is at a temperature at least above about 2O0C and below about 7O0C.
10. A process in accordance with claim 1 wherein said treated liquid hydrocarbon stream contains less than about 50 wt. % of the total Hg contained in said liquid hydrocarbon stream.
11. A process in accordance with claim 1 wherein said treated liquid hydrocarbon stream contains less than about 20 wt. % of the total Hg contained in said liquid hydrocarbon stream.
12. A process in accordance with claim 1 wherein said treated liquid hydrocarbon stream contains less than about 1 wt. % of the total Hg contained in said liquid hydrocarbon stream.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US12/241,126 US20100078358A1 (en) | 2008-09-30 | 2008-09-30 | Mercury removal process |
| PCT/US2009/058799 WO2010039716A1 (en) | 2008-09-30 | 2009-09-29 | Mercury removal process |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| EP2352567A1 true EP2352567A1 (en) | 2011-08-10 |
Family
ID=41259675
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| EP09793119A Withdrawn EP2352567A1 (en) | 2008-09-30 | 2009-09-29 | Mercury removal process |
Country Status (4)
| Country | Link |
|---|---|
| US (1) | US20100078358A1 (en) |
| EP (1) | EP2352567A1 (en) |
| AU (1) | AU2009298710B2 (en) |
| WO (1) | WO2010039716A1 (en) |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| US8489231B2 (en) * | 2009-09-18 | 2013-07-16 | Raf Technology, Inc. | Loop mail processing |
| CN103097495A (en) * | 2010-09-16 | 2013-05-08 | 雪佛龙美国公司 | Process, method, and system for removing heavy metals from fluids |
| US8673133B2 (en) * | 2010-09-16 | 2014-03-18 | Chevron U.S.A. Inc. | Process, method, and system for removing heavy metals from fluids |
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| US9296956B2 (en) | 2010-10-28 | 2016-03-29 | Chevron U.S.A. Inc. | Method for reducing mercaptans in hydrocarbons |
| BR112013012087A2 (en) * | 2010-11-19 | 2016-08-16 | Chevron Usa Inc | process, method, and system for removing heavy metals from fluids |
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| BR112014026732A2 (en) * | 2012-05-16 | 2017-06-27 | Chevron Usa Inc | duct reaction for the removal of heavy metals from the fluids produced |
| SG11201407563QA (en) | 2012-05-16 | 2014-12-30 | Chevron Usa Inc | Process, method, and system for removing mercury from fluids |
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| SG11201407565SA (en) | 2012-05-16 | 2014-12-30 | Chevron Usa Inc | Process, method, and system for removing mercury from fluids |
| US9447674B2 (en) | 2012-05-16 | 2016-09-20 | Chevron U.S.A. Inc. | In-situ method and system for removing heavy metals from produced fluids |
| US9023196B2 (en) | 2013-03-14 | 2015-05-05 | Chevron U.S.A. Inc. | Process, method, and system for removing heavy metals from fluids |
| US9234141B2 (en) | 2013-03-14 | 2016-01-12 | Chevron U.S.A. Inc. | Process, method, and system for removing heavy metals from oily solids |
| US9169445B2 (en) | 2013-03-14 | 2015-10-27 | Chevron U.S.A. Inc. | Process, method, and system for removing heavy metals from oily solids |
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| US4601816A (en) * | 1984-08-09 | 1986-07-22 | Mobil Oil Corporation | Upgrading heavy hydrocarbon oils using sodium hypochlorite |
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| US3476552A (en) * | 1966-09-07 | 1969-11-04 | Mountain Copper Co Of Californ | Mercury process |
| US3899570A (en) * | 1973-02-09 | 1975-08-12 | Wisconsin Alumni Res Found | Extraction of mercuric chloride from dilute solution and recovery |
| SE396772B (en) * | 1975-09-16 | 1977-10-03 | Boliden Ab | PROCEDURE FOR EXTRACTION AND EXTRACTION OF MERCURES FROM GASES |
| ES447417A1 (en) * | 1976-04-28 | 1977-07-01 | Diaz Nogueira Eduardo | PROCEDURE FOR THE ELIMINATION OF MERCURY FROM WASTEWATER BY EXTRACTION WITH SOLVENTS. |
| US4101631A (en) * | 1976-11-03 | 1978-07-18 | Union Carbide Corporation | Selective adsorption of mercury from gas streams |
| US4915818A (en) * | 1988-02-25 | 1990-04-10 | Mobil Oil Corporation | Use of dilute aqueous solutions of alkali polysulfides to remove trace amounts of mercury from liquid hydrocarbons |
| CA1323321C (en) * | 1988-07-25 | 1993-10-19 | Kunio Sato | Process for removal of mercury from a liquid hydrocarbon |
| US5017280A (en) * | 1990-05-08 | 1991-05-21 | Laboratorios Paris, C.A. | Process for recovering metals and for removing sulfur from materials containing them by means of an oxidative extraction |
| US5223145A (en) * | 1992-10-09 | 1993-06-29 | Uop | Removal of mercury from process streams |
| US5226545A (en) * | 1992-10-19 | 1993-07-13 | General Electric Company | Extraction of mercury and mercury compounds from contaminated material and solutions |
| JP2633484B2 (en) * | 1993-12-22 | 1997-07-23 | 三井石油化学工業株式会社 | Method for removing mercury from liquid hydrocarbons |
| US5900042A (en) * | 1997-08-18 | 1999-05-04 | The United States Of America As Represented By The United States Department Of Energy | Method for the removal of elemental mercury from a gas stream |
| US6268543B1 (en) * | 1998-11-16 | 2001-07-31 | Idemitsu Petrochemical Co., Ltd. | Method of removing mercury in liquid hydrocarbon |
| US6855859B2 (en) * | 1999-03-31 | 2005-02-15 | The Babcock & Wilcox Company | Method for controlling elemental mercury emissions |
| US6350372B1 (en) * | 1999-05-17 | 2002-02-26 | Mobil Oil Corporation | Mercury removal in petroleum crude using H2S/C |
| JP3546160B2 (en) * | 1999-12-10 | 2004-07-21 | 三菱重工業株式会社 | Mercury removal method |
| US6537443B1 (en) * | 2000-02-24 | 2003-03-25 | Union Oil Company Of California | Process for removing mercury from liquid hydrocarbons |
| KR100809192B1 (en) * | 2000-10-30 | 2008-02-29 | 이데미쓰 고산 가부시키가이샤 | How to remove mercury from liquid hydrocarbons |
| JP3872677B2 (en) * | 2001-10-31 | 2007-01-24 | 三菱重工業株式会社 | Mercury removal method and system |
| WO2005066313A2 (en) * | 2003-12-24 | 2005-07-21 | Saudi Arabian Oil Company | Reactive extraction of sulfur compounds from hydrocarbon streams |
| US8034741B2 (en) * | 2005-11-09 | 2011-10-11 | Gore Enterprise Holdings, Inc. | Capture of mercury from a gaseous mixture containing mercury |
| US8034246B2 (en) * | 2007-05-16 | 2011-10-11 | Exxonmobil Research & Engineering Company | Wastewater mercury removal process |
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- 2008-09-30 US US12/241,126 patent/US20100078358A1/en not_active Abandoned
-
2009
- 2009-09-29 WO PCT/US2009/058799 patent/WO2010039716A1/en not_active Ceased
- 2009-09-29 AU AU2009298710A patent/AU2009298710B2/en not_active Expired - Fee Related
- 2009-09-29 EP EP09793119A patent/EP2352567A1/en not_active Withdrawn
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| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US4601816A (en) * | 1984-08-09 | 1986-07-22 | Mobil Oil Corporation | Upgrading heavy hydrocarbon oils using sodium hypochlorite |
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| AU2009298710B2 (en) | 2014-07-24 |
| US20100078358A1 (en) | 2010-04-01 |
| AU2009298710A1 (en) | 2010-04-08 |
| WO2010039716A1 (en) | 2010-04-08 |
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