Abstract: Oil is recovered from a mercury containing Hg-containing solids containing abradants by mixing the solids with a sulfidic compound in a molar ratio of sulfur compound to mercury from 5:1 to 5,000:1, and the sulfidic compound when dissolved in water, yields S2-, SH—, Sx2-, or SxH— anions, and optionally a solvent, forming a mixture. The mixture is then separated to recover a first phase containing treated oil in water, and a second phase containing treated abradants having a reduced concentration of mercury. In one embodiment, the treated abradants contain less than 100 ppmw mercury. The abradants are provided by removing at least a portion of a mercury-containing coating from a surface by abradant blasting, laser ablation, laser thermal desorption, and sponge jet blasting.

Abstract: A predictive tool is provided for estimating the mercury content of hydrocarbons to be produced from a wellbore in a newly investigated subterranean hydrocarbon producing formation based on the mercury content of an inorganic sample recovered from the wellbore. The mercaptans content of liquid hydrocarbons and/or the hydrogen sulfide content of natural gas produced from the formation may also be used to enhance the prediction. Based on the predicted value, a mercury mitigation treatment may be provided to mitigate the mercury content of hydrocarbons produced from the formation.

Abstract: Disclosed herein is a method for improving the total energy demand required to separate carbon dioxide (CO2) from an aqueous ionic absorbent solution in a post-combustion carbon capture process. The method involves (a) contacting a flue gas stream containing CO2 with an aqueous ionic absorbent solution under absorption conditions to absorb at least a portion of the CO2 from the flue gas stream and form a CO2-aqueous ionic absorbent solution stream, wherein the aqueous ionic absorbent solution comprises one or more diluents and an ionic absorbent containing a cation and an anion comprising an amine moiety; and (b) subjecting at least a portion of the CO2-aqueous ionic absorbent solution stream to desorption conditions to form a CO2-rich stream and an aqueous ionic absorbent solution stream having a reduced CO2 content.

Abstract: A method for concurrently transporting and removing trace amount levels of heavy metals such as mercury from produced fluids such as natural gas, with the injection of a complexing agent and a hydrate inhibitor into the pipeline for use in transporting the produced fluid. Volatile mercury in the natural gas is removed while the produced fluid is being transported in the pipeline, with the hydrate inhibitor suppressing or decreasing the formation of the hydrate that would cause plugging in the pipeline. The complexing agent reacts with the volatile mercury in the natural gas, forming precipitate or soluble mercury complexes in the aqueous phase. The aqueous phase containing the hydrate inhibitor, unreacted complexing agent, and mercury complexes is subsequently recovered and can be re-used in the pipeline.

Abstract: An aqueous ionic absorbent solution is disclosed containing (a) about 15 wt. % to about 80 wt. % of one or more diluents, based on the total weight of the aqueous ionic absorbent solution; and (b) an ionic absorbent containing a cation and an anion comprising an amine moiety.

Abstract: Trace amount levels of non-volatile mercury in crude oil are reduced by contacting the crude oil with a water stream containing at least a monatomic water-soluble sulfur species such as sulfides and hydrosulfides. The non-volatile mercury is extracted into the water phase forming a mercury rich wastewater, yielding a treated crude oil having at less than 50% of the original non-volatile mercury level. The wastewater can disposed or recycled by injection into a reservoir. In one embodiment, the water stream consists essentially of produced water.

Abstract: Oil is recovered from a mercury containing oily solids by mixing the solids with at least a treating agent selected from selected from flocculants, sulfidic compounds, demulsifiers, and combinations thereof, and optionally a solvent, forming a mixture. The mixture is then separated to recover a first phase containing treated oil having less than 50% of the original amount of mercury in the oily solids, and a second phase containing treated solids having a reduced concentration of mercury. In one embodiment, the oily solids comprise filter aid materials, e.g., diatomaceous earth filter media, removed from a mercury removal filtration unit by backflushing the filter.

Abstract: Trace element levels of mercury in crude oil are reduced by first passing the crude oil through a filtration device to generate filtered crude having a reduced concentration of mercury and a reject stream having a concentrated mercury level. In one embodiment, the filtration device is back-flushed to generate the reject stream. In another embodiment, the reject stream comprises a portion of the retentate from a cross-flow filter device. The reject stream is treated with an extractive agent selected from tetrakis(hydroxymethyl)phosphonium sulfate; tetrakis(hydroxymethyl) phosphonium chloride; an oxidizing agent; an organic or inorganic sulfidic compound to extract a portion of the mercury into a water phase for subsequent removal. In one embodiment, the extractive agent is a reductant to convert non-volatile mercury into volatile mercury.

Abstract: Trace levels of mercury in a natural gas are reduced by scrubbing the natural gas in an absorber with an aqueous solution comprising a water-soluble sulfur compound. The water-soluble sulfur compound reacts with a least a portion of the mercury in the natural gas to produce a treated natural gas with a reduced concentration of mercury, and a mercury containing sulfur-depleted solution which can be disposed by injection into a (depleted) underground formation. The produced water extracted with the natural gas from the underground formation can be recycled for use as the scrubbing solution. In one embodiment, a fresh source of water-soluble sulfur compound as feed to the absorber can be generated on-site by reacting an elemental sulfur source with a sulfur reagent in produced water.

Abstract: Trace amount levels of heavy metals such as mercury in crude oil are reduced by contacting the crude oil with a sufficient amount of a reducing agent to convert at least a portion of the non-volatile mercury into a volatile form of mercury, which can be subsequently removed by any of stripping, scrubbing, adsorption, and combinations thereof. In one embodiment, at least 50% of the mercury is removed. In another embodiment, the removal rate is at least 99%. In one embodiment, the reducing agent is selected from sulfur compounds containing at least one sulfur atom having an oxidation state less than +6; ferrous compounds; stannous compounds; oxalates; cuprous compounds; organic acids which decompose to form CO2 and/or H2 upon heating; hydroxylamine compounds; hydrazine compounds; sodium borohydride; diisobutylaluminium hydride; thiourea; transition metal halides; and mixtures thereof.

Abstract: Mercury in distilled products from a distillation column is removed and extracted as soluble mercury compounds with the injection of a complexing agent into the overhead sections of the column. Examples of complexing agents include polysulfides such as sodium polysulfide or ammonium polysulfide. In one embodiment, the complexing agent is injected into the inlet pipe just before the overhead condenser, converting the volatile elemental mercury into a species that is soluble in the sour water stream that collected in the overhead sections.

Abstract: A process and system for separating CO2 from a flue gas stream is disclosed. The process involves (a) contacting a flue gas stream containing water vapor and CO2 with an ionic absorbent under absorption conditions to absorb at least a portion of the CO2 from the flue gas stream and form a CO2-absorbent complex; wherein the ionic absorbent comprises a cation and an anion comprising an amine moiety; and (b) recovering a gaseous product having a reduced CO2 content.

Abstract: A process and system for separating CO2 from a flue gas stream is disclosed. The process involves (a) contacting a flue gas stream containing water vapor and CO2 with an ionic absorbent under absorption conditions to absorb at least a portion of the CO2 from the flue gas stream and form a CO2-absorbent complex; wherein the ionic absorbent comprises a cation and an anion comprising an amine moiety; and (b) recovering a gaseous product having a reduced CO2 content.

Abstract: Trace levels of mercury in a natural gas are removed in a gas processing plant in an amine unit and/or a dehydrator. The mercury removal occurs concurrently with the removal of acid gases in an amine unit, e.g., an absorber or scrubber, with an amine solution containing a complexing agent. The mercury removal can also be carried out concurrently with the removal of water in a glycol dehydrator with the addition of a complexing agent to the glycol solution. Volatile mercury in the natural gas is removed by the complexing agent, forming non-volatile mercury species in the rich amine/glycol solution.

Abstract: Trace element levels of mercury in crude oil are reduced by first passing the crude oil through a filtration device to generate filtered crude having a reduced concentration of mercury and a reject stream having a concentrated mercury level. In one embodiment, the filtration device is back-flushed to generate the reject stream. In another embodiment, the reject stream comprises a portion of the retentate from a cross-flow filter device. The reject stream is treated with an extractive agent selected from tetrakis(hydroxymethyl)phosphonium sulfate; tetrakis(hydroxymethyl) phosphonium chloride; an oxidizing agent; an organic or inorganic sulfidic compound to extract a portion of the mercury into a water phase for subsequent removal. In one embodiment, the extractive agent is a reductant to convert non-volatile mercury into volatile mercury.

Abstract: Oil is recovered from a mercury containing oily solids by mixing the solids with at least a treating agent selected from selected from flocculants, sulfidic compounds, demulsifiers, and combinations thereof, and optionally a solvent, forming a mixture. The mixture is then separated to recover a first phase containing treated oil having less than 50% of the original amount of mercury in the oily solids, and a second phase containing treated solids having a reduced concentration of mercury. In one embodiment, the oily solids comprise filter aid materials, e.g., diatomaceous earth filter media, removed from a mercury removal filtration unit by backflushing the filter.

Abstract: Oil is recovered from a mercury containing oily solids by mixing the solids with at least a treating agent selected from selected from flocculants, sulfidic compounds, demulsifiers, and combinations thereof, and optionally a solvent, forming a mixture. The mixture is then separated to recover a first phase containing treated oil having less than 50% of the original amount of mercury in the oily solids, and a second phase containing treated solids having a reduced concentration of mercury. The oily solids are selected from drilling muds; oily sediments coating inside of pipelines; sediment deposits on crude oil tanks, vessels, and separators; surface coating on equipment; slop oil from upstream operations; oily solids from heavy oil processing operations; solids recovered from processes for removing mercury from hydrocarbon materials; spill clean-up materials; and mixtures thereof.

Abstract: Oil is recovered from a mercury containing Hg-containing solids containing abradants by mixing the solids with a sulfidic compound in a molar ratio of sulfur compound to mercury from 5:1 to 5,000:1, and the sulfidic compound when dissolved in water, yields S2-, SH—, Sx2-, or SxH— anions, and optionally a solvent, forming a mixture. The mixture is then separated to recover a first phase containing treated oil in water, and a second phase containing treated abradants having a reduced concentration of mercury. In one embodiment, the treated abradants contain less than 100 ppmw mercury. The abradants are provided by removing at least a portion of a mercury-containing coating from a surface by abradant blasting, laser ablation, laser thermal desorption, and sponge jet blasting.

Abstract: Trace levels of mercury in a natural gas are removed in a gas processing plant in an amine unit and/or a dehydrator. The mercury removal occurs concurrently with the removal of acid gases in an amine unit, e.g., an absorber or scrubber, with an amine solution containing a complexing agent. The mercury removal can also be carried out concurrently with the removal of water in a glycol dehydrator with the addition of a complexing agent to the glycol solution. Volatile mercury in the natural gas is removed by the complexing agent, forming non-volatile mercury species in the rich amine/glycol solution.

Abstract: Methods and systems relate to the in-situ removal of heavy metals such as mercury, arsenic, etc., from produced fluids such as gases and crudes from a subterranean hydrocarbon-bearing formation. A sufficient amount of a fixing agent is injected into formation with a dilution fluid. The fixing agent reacts with the heavy metals forming precipitate, or is extracted heavy metals into the dilution fluid as soluble complexes. In one embodiment, the heavy metal precipitates remain in the formation. After the recovery of the produced fluid, the dilution fluid containing the heavy metal complexes is separated from the produced fluid, generating a treated produced fluid having a reduced concentration of heavy metals. In one embodiment, the dilution fluid is water, and the wastewater containing the heavy metal complexes after recovery can be recycled by injection into a reservoir.