WO2024252361A1

WO2024252361A1 - Mercury removal from hydrocarbon fluids

Info

Publication number: WO2024252361A1
Application number: PCT/IB2024/055608
Authority: WO
Inventors: Sharizal B Mohd Azam Shah WONG; TG M Uzaini B TG MAT; M Syamzari B RAFEEN; Safwan B A SALAM; John Holbrey; Emily Byrne
Original assignee: Petroliam Nasional Berhad (Petronas)
Priority date: 2023-06-07
Filing date: 2024-06-07
Publication date: 2024-12-12

Abstract

This invention relates to a process for removing mercury from mercury-containing hydrocarbon fluid feeds, and more specifically by use an active organic salt composition.

Description

MERCURY REMOVAL FROM HYDROCARBON FLUIDS

FIELD OF THE INVENTION

This invention relates to a process for removing mercury from mercury-containing hydrocarbon fluid feeds. More specifically, the invention relates to a process of extracting mercury from a hydrocarbon fluid feed using an active organic salt composition, methods for producing active organic salt compositions and uses thereof.

BACKGROUND OF THE INVENTION

Liquid and gaseous hydrocarbons obtained from oil and gas fields are often contaminated with mercury. In particular, liquid and gaseous hydrocarbons obtained from oil and gas fields in and around the Netherlands, Germany, Canada, USA, Malaysia, Brunei and the UK are known to contain mercury. As reported by N. S. Bloom (Fresenius J. Anal. Chem., 2000, 366, 438-443), the mercury content of such hydrocarbons may take a variety of forms. Although elemental mercury tends to predominate, particulate mercury (i.e. mercury bound to particulate matter), organic mercury (e.g. dimethylmercury and diethylmercury) and ionic mercury (e.g. mercury dichloride) may also be found in naturally occurring hydrocarbon sources. The mercury concentration in crude oils can range from typically below 1 part per billion (ppb) to several thousand ppb depending on the well and location. Similarly, mercury concentrations in natural gas can range from below 1 ng m^-3 to greater than 1000 pg m^-3.

The presence of mercury in hydrocarbons is problematic due to its toxicity. In addition, mercury is corrosive towards hydrocarbon processing equipment, such as that used in oil and gas refineries. Mercury can react with aluminium components of hydrocarbon processing equipment to form an amalgam, which can lead to equipment failure. For example, pipeline welds, cryogenic components, aluminium heat exchangers and hydrogenation catalysts can all be damaged by hydrocarbons contaminated with mercury. This can lead to plant shutdown, with severe economic implications, or, in extreme cases, to uncontrolled loss of containment or complete plant failure, with potentially catastrophic results. Furthermore, products with high levels of mercury contamination are considered to be of poorer quality, with the result that they command a lower price. Mercury can be found in both produced gaseous and liquid hydrocarbon streams. However, the bulk of mercury tends to accumulate in produced liquid streams such as natural gas condensate and produced waters.

A number of approaches to the removal of mercury from hydrocarbons have been proposed. These include: scrubbing techniques using fixed bed columns containing sulfur, transition metal or heavy metal sulfides and iodides on an activated support; oxidation followed by complexation with sulfur-containing compounds; and oxidation followed by solvent extraction.

A typical method of processing hydrocarbon fluid feeds, such as natural gases, comprises the following steps. A feed gas is first cooled before entering a separator, wherein the gas is separated into a gas feed (consisting primarily of Ci to C4 alkanes), a condensate feed (predominantly comprising C5 to C₈ alkanes) and a produced water feed. The condensate is then further processed by i) dewatering, ii) removal of solids through filtering and iii) mercury removal in a mercury removal unit (MRU) before the resulting product is exported. The produced water undergoes the processing steps of i) de-oiling, ii) degassing and iii) mercury removal in a mercury removal unit (MRU) before the treated water is either disposed of or recycled. Finally, the gas separated from the hydrocarbon feed is dehydrated and compressed before being exported.

The most common form of attempted mercury removal from both produced gaseous and liquid hydrocarbon fluids in the oil and gas industry is through the use of mercury removal units (MRUs) which are included as units attached to the conduits for transporting and processing hydrocarbon fluids. Mercury removal units involve the use of fixed bed adsorbents such as activated carbon, zeolite and alumina, through which hydrocarbon fluids comprising a mercury species can flow, removing at least a portion of mercury present, forming cinnabar (HgS) on the fixed bed.

Whilst the use of mercury removal units can in some instances be effective at lowering the concentration of mercury in hydrocarbon fluids, reliance on said units also has associated drawbacks. For example, as mercury removal units comprise adsorbents, the amount of mercury which can be removed from a hydrocarbon fluid is dependent, at least in part, on the amount of adsorbent present and the amount of mercury-containing hydrocarbon fluid which has previously been treated. Accordingly, where the mercury concentration of the hydrocarbon fluids flowing into the units varies, treated hydrocarbon fluids may also have a large variance in mercury concentration. Another problem is that the adsorbents often require premature changing and replacement due to collapse of the solid support or leaching of the active chemical agent by the fluid flow of the hydrocarbons. Collapse of the solid support can also occur due to the presence of other contaminants in the hydrocarbon fluid. The process of replacing the adsorbents is complex and the handling of the spent adsorbents can be hazardous. The mercury removal units also occupy a large area and are heavy, making them unsuitable for inclusion in certain conduits and systems. These units can also be prone to large pressure drops across the adsorbent bed due to damage of adsorbent physical integrity which can result in problems with their operations. All of these issues contribute to high capital and operational costs as well as causing certain health and safety concerns.

Other approaches for removing mercury from hydrocarbon fluids, such as crude oil, can be seen for example in US 9,523,043. The process comprises the steps of i) fractionally distilling a crude product containing at least 50 ppbw mercury to form overhead vapor fractions comprising light naphtha having a first concentration of mercury; ii) contacting the overhead vapor fractions with a complexing agent to convert at least a portion of mercury into water soluble mercury in solution, producing a light naphtha product having a reduced concentration of mercury; iii) removing the solution containing water soluble mercury from the crude distillation unit; and iv) recovering the light naphtha product from an upper section of the distillation column. US ‘043 teaches that the complexing agent is selected from inorganic and organic polysulfides, such as sodium polysulfide, calcium polysulfide, ammonium polysulfide, di-tertbutyl polysulfide (TBPS) and amine polysulfide, or alternatively sodium thiocarbamate, sodium dithiocarbamate, ammonium thiocarbamate, ammonium dithiocarbamate, and mixtures thereof.

US 9,023,123 and US 8,790,427 disclose methods of removing mercury from hydrocarbon fluids such as natural gas. In particular, US 9,023,123 discloses a method comprising the steps of i) recovering a mixture of produced water and mercury-containing natural gas from an underground reservoir; ii) separating the mercury-containing natural gas from the produced water; iii) scrubbing the natural gas with an aqueous solution in an absorber, wherein the aqueous solution comprises a water-soluble sulfur compound to react with at least a portion of mercury present, producing a treated natural gas with a reduced concentration of mercury and a mercury containing sulfur-depleted solution; iv) removing at least a portion of the mercury containing sulfur-depleted solution as a purge stream v) recirculating at least a portion of the mercury containing sulfur-depleted solution as a recirculating stream; and vi) providing a fresh source of water-soluble sulfur compound as a feed to the absorber for reaction with mercury in the natural gas. The water-soluble sulfur compounds may be selected from sodium hydrosulfide, potassium hydrosulfide, ammonium hydrosulfide, sodium sulfide, potassium sulfide, calcium sulfide, magnesium sulfide, ammonium sulfide, and mixtures thereof.

US 8,790,427 discloses a method comprising the step of incorporating a mercury removal process with an amine treating unit. In particular, a complexing agent is added to an adsorber comprising an amine scrubbing solution to remove acid gases such as hydrogen sulfide (H₂S) and carbon dioxide from the sour feed steam. In an alternative embodiment, the complexing agent is present in a glycol solution feed in a dehydrator unit. The complexing agent is preferably selected from amine polysulfides, sodium hydrosulfide, potassium hydrosulfide, ammonium hydrosulfide, sodium sulfide, potassium sulfide, calcium sulfide, magnesium sulfide, ammonium sulfide, sodium thiocarbamate, sodium dithiocarbamate, ammonium thiocarbamate, ammonium dithiocarbamate, and mixtures thereof or alternatively mercaptans, organic polysulfides (compounds of the general formula R- S_x- R' where x is greater than 1 and R and R' are alkyl or aryl groups), sulfanes, and combinations thereof.

In addition, a limited number of approaches have been proposed for the removal of mercury from hydrocarbon fluids using ionic liquids. For example, the combination of metal-complexing ligands and ionic liquids coated onto an inert support as adsorbents to remove mercury from coal combustion flue gases has been described in US Patent Application 2007/0123660 and by Ji et al. (Water, Air, & Soil Pollution: Focus 2008, 8, 349-358 and Ind. Eng. Chem. Res., 2008, 47, 8396-8400). The term “ionic liquid” as used herein refers to a liquid that is capable of being produced by melting a salt, and when so produced consists solely of ions. An ionic liquid may be formed from a homogeneous substance comprising one species of cation and one species of anion, or it can be composed of more than one species of cation and/or more than one species of anion. Thus, an ionic liquid may be composed of more than one species of cation and one species of anion. An ionic liquid may further be composed of one species of cation, and one or more species of anion. Still further, an ionic liquid may be composed of more than one species of cation and more than one species of anion.

The term “ionic liquid” includes compounds having both high melting points and compounds having low melting points, e.g. at or below room temperature. Thus, many ionic liquids have melting points below 200 °C, particularly below 100 °C, around room temperature (15 to 30 °C), or even below 0 °C. Ionic liquids having melting points below around 30 °C are commonly referred to as “room temperature ionic liquids” and are often derived from organic salts having nitrogen-containing heterocyclic cations, such as imidazolium and pyridinium-based cations. In room temperature ionic liquids, the structures of the cation and anion prevent the formation of an ordered crystalline structure and therefore the salt is liquid at room temperature.

Ionic liquids are most widely known as solvents. Many ionic liquids have been shown to have negligible vapour pressure, temperature stability, low flammability and recyclability. Due to the vast number of anion/cation combinations that are available it is possible to fine-tune the physical properties of the ionic liquid (e.g. melting point, density, viscosity, and miscibility with water or organic solvents) to suit the requirements of a particular application.

There is therefore a need for a more reliable and effective method of removing mercury from hydrocarbon feeds, particularly where the concentration of mercury at the inlet may be variable. In addition, it is desirable to provide a more cost-effective method of extracting mercury species from hydrocarbon fluids. The present invention is based on the surprising discovery that active organic salt compositions comprising a mixture of an ionic liquid and sulfur salt can be used to increase the amount of mercury extracted from mercury-containing hydrocarbon fluid feeds. It is believed that the use of an ionic liquid as defined herein facilitates an increased interaction between the activated sulfur salt species and the hydrocarbon feed, as well as any water present therein, resulting in an increased interaction between the sulfur salt species formed in the ionic liquid and mercury species present within these feeds. The present invention therefore provides a more effective and reliable method of producing hydrocarbon products meeting industry implemented limitations with regards to mercury concentration in a more time and cost-effective manner.

Thus, in a first aspect, the present invention provides a process for removing mercury from a mercury-containing hydrocarbon fluid feed, the process comprising the steps of:

(i) contacting the mercury containing hydrocarbon feed with an active organic salt composition comprising a mixture of an ionic liquid and a sulfur salt, the ionic liquid having the formula:

[Cat⁺][X-] wherein: [Cat⁺] represents one or more cationic species; and

[X-] represents one or more alkyl carboxylic acid species; and

(ii) separating a hydrocarbon fluid product having a reduced mercury content compared to the mercury containing hydrocarbon feed.

The process of the invention may be applied to substantially any hydrocarbon feed which comprises mercury, and which is liquid or gaseous under the operating conditions of the process. Thus, hydrocarbon fluids that may be processed according to the present invention include liquid hydrocarbons, such as liquefied natural gas; light distillates, including liquid petroleum gas, gasoline, and/or naphtha; natural gas condensates; middle distillates, such as kerosene and/or diesel; heavy distillates, such as fuel oil; and crude oils. Hydrocarbon fluids that may be processed according to the present invention also include gaseous hydrocarbons, such as natural gas and refinery gas. Preferably the hydrocarbon fluid comprises a liquid hydrocarbon. The above-mentioned process may be used as an alternative method of removing mercury from mercury-containing hydrocarbon fluid feeds compared to previous methods comprising the use of mercury removal units. In some embodiments, the process of removing mercury from a mercury-containing hydrocarbon fluid feed does not comprise the use of a mercury removal unit. In an alternative embodiment, the present invention may be used in combination with a mercury removal unit. The inclusion of a first step of at least partly removing mercury from a hydrocarbon feed in accordance with the present invention can reduce the occurrence of premature saturation of mercury adsorbents within the mercury removal unit. In addition the use of a process as defined herein in combination with a mercury removal unit allows greater control with regards to the concentration of mercury in the treated hydrocarbon fluid product, despite varying amounts of mercury within the feed material.

The step of contacting the hydrocarbon feed with an active organic salt composition may in principle be performed at any stage of processing the fluid hydrocarbon feed. In particular, an active organic salt composition as defined above may be injected directly into an underground reservoir. In an alternative embodiment, the active organic salt composition may be injected into the hydrocarbon feed prior to the feed entering a separator, for example to separate the hydrocarbon stream from water which might be present. In a further example, the active organic salt composition may be contacted with the separated condensate feed following a dewatering step, directly prior to the feed entering the mercury removal unit or directly prior to exporting the condensate product. In yet a still further example, the active organic salt composition may be contacted with the separated produced water feed following a de-oiling process step or directly prior to the feed entering the mercury removal unit. In embodiments where the process further comprises a mercury removal unit, the active organic salt composition is preferably contacted with the mercury containing hydrocarbon feed upstream of the mercury removal unit. By first contacting the hydrocarbon feed with the active organic salt composition, the life span of adsorbents present in the mercury removal unit is increased, thereby improving the cost efficiency of the overall process.

In accordance with the present invention, [X-] may be selected from one or more carboxylic acid species of a formula [R¹-CC>2]', wherein R¹ is selected from a Ci to C20 branched or linear chain alkyl. Preferably, R¹ is selected from a C₂ to C14 linear or branched alkyl, more preferably a C₂ to Ci₂ linear or branched alkyl. Most preferably, R¹ is selected from hexyl, heptyl, octyl, 2-ethylhexyl and decyl, and combinations thereof.

In accordance with the present invention, [Cat⁺] may comprise a cationic species selected from: ammonium, azaannulenium, azathiazolium, benzimidazolium, benzofuranium, benzotriazolium, borolium, cinnolinium, diazabicyclodecenium, diazabicyclononenium, diazabicyclo-undecenium, dithiazolium, furanium, imidazolium, indazolium, indolinium, indolium, morpholinium, oxaborolium, oxaphospholium, oxazinium, oxazolium, iso- oxazolium, oxothiazolium, pentazolium, phospholium, phosphonium, phthalazinium, piperazinium, piperidinium, pyranium, pyrazinium, pyrazolium, pyridazinium, pyridinium, pyrimidinium, pyrrolidinium, pyrrolium, quinazolinium, quinolinium, /so-quinolinium, quinoxalinium, selenozolium, sulfonium, tetrazolium, /so-thiadiazolium, thiazinium, thiazolium, thiophenium, triazadecenium, triazinium, triazolium, and /so-triazolium.

In one preferred embodiment of the invention, [Cat⁺] comprises an aromatic heterocyclic cationic species selected from: benzimidazolium, benzofuranium, benzotriazolium, cinnolinium, diazabicyclodecenium, diazabicyclononenium, diazabicyclo-undecenium, dithiazolium, imidazolium, indazolium, indolinium, indolium, oxazinium, oxazolium, iso- oxazolium, oxathiazolium, phthalazinium, pyrazinium, pyrazolium, pyridazinium, pyridinium, pyrimidinium, quinazolinium, quinolinium, /so-quinolinium, quinoxalinium, tetrazolium, /so-thiadiazolium, thiazinium, thiazolium, triazinium, triazolium, and /so- triazolium. ln one embodiment, [Cat⁺] may be selected from the group consisting of:

wherein: R^a, R^b, R^c, R^d, R^e, R^f and R⁹ are each independently selected from hydrogen, a Ci to C30, straight chain or branched alkyl group, a C3 to C₈ cycloalkyl group, or a Ce to C10 aryl group, wherein said alkyl, cycloalkyl or aryl groups are unsubstituted or may be substituted by one to three groups selected from: Ci to Ce alkoxy, C₂ to Ci₂ alkoxyalkoxy, C3 to C₈ cycloalkyl, Ce to C10 aryl, -CN, -OH, -SH, -NO₂, Ce to C10 aryl and C7 to C10 alkaryl, -CO₂(Ci to Ce)alkyl, -OC(O)(Ci to Ce)alkyl, or any two of R^b, R^c, R^d, R^e and R^f attached to adjacent carbon atoms form a methylene chain -(CH₂)_q- wherein q is from 3 to 6.

Preferably, R^a, R^b, R^c, R^d, R^e, R^f and R⁹ are each independently selected from a Ci to C₂o straight chain or branched alkyl group, a C3 to Ce cycloalkyl group, or a Ce aryl group, wherein said alkyl, cycloalkyl or aryl groups are unsubstituted or may be substituted by one to three groups selected from: Ci to Ce alkoxy, C₂ to Ci₂ alkoxyalkoxy, C3 to C₈ cycloalkyl, Ce to C10 aryl, -CN, -OH, -SH, -NO₂, -CO₂(Ci to Ce)alkyl, -OC(O)(Ci to Ce)alkyl, Ce to C10 aryl and C7 to C10 alkaryl, and wherein one of R^b, R^c, R^d, R^e, R^f and R⁹ may also be hydrogen. R^a is preferably selected from Ci to C30, linear or branched, alkyl, more preferably C₂ to C₂o linear or branched alkyl, still more preferably, C₂ to C10 linear or branched alkyl, and most preferably R^a is selected from ethyl, n-butyl, n-hexyl and n-octyl. Further examples include wherein R^a is selected from methyl, ethyl, n-propyl, n-butyl, n-pentyl, n-hexyl, n- heptyl, n-octyl, n-nonyl, n-decyl, n-undecyl, n-dodecyl, n-tridecyl, n-tetradecyl, n- pentadecyl, n-hexadecyl, n-heptadecyl and n-octadecyl.

In the cations comprising an R⁹ group, R⁹ is preferably selected from Ci to C10 linear or branched alkyl, more preferably, Ci to C5 linear or branched alkyl, and most preferably R⁹ is a methyl group.

In the cations comprising both an R^a and an R⁹ group, R^a and R⁹ are each preferably independently selected from Ci to C30, linear or branched, alkyl, and one of R^a and R⁹ may also be hydrogen. More preferably, one of R^a and R⁹ may be selected from C₂ to C₂₀ linear or branched alkyl, still more preferably, C₂ to C10 linear or branched alkyl, and most preferably C4 to C₈ linear or branched alkyl, and the other one of R^a and R⁹ may be selected from Ci to C10 linear or branched alkyl, more preferably, Ci to C5 linear or branched alkyl, and most preferably a methyl group. In a further preferred embodiment, R^a and R⁹ may each be independently selected, where present, from Ci to C30 linear or branched alkyl and Ci to Ci 5 alkoxyalkyl.

In another embodiment, the cation may be selected from the group consisting of:

[N(R^a)(R^b)(R^c)(R^d)]⁺, [P(R^a)(R^b)(R^c)(R^d)]⁺, and [S(R^a)(R^b)(R^c)]⁺, wherein: R^a, R^b, R^c and R^d are as defined above.

Preferably, the cation is selected from:

[N(R^a)(R^b)(R^c)(R^d)]⁺ and [P(R^a)(R^b)(R^c)(R^d)]⁺, wherein: R^a, R^b, R^c and R^d are each independently selected from Ci to C₈, straight or branched chain, alkyl, including C₂ ,C4 and C₈ alkyl. Most preferably, the acyclic cation is [N(R^a)(R^b)(R^c)(R^d)]⁺.

In a preferred embodiment, R^a, R^b, R^c and R^d are the same, and optionally selected from Ci to C₈ straight chain alkyl (methyl, ethyl, n-propyl, n-butyl, n-pentyl, n-hexyl, n-heptyl, n- octyl), such as C2 to Ce alkyl (ethyl, n-propyl, n-butyl, n-pentyl, n-hexyl).

In some embodiments, [Cat⁺] may be selected from tetrabutylammonium.

In some embodiments, the ionic liquid, [Cat⁺][X^_], may be selected from one or more of tetrabutylammonium 2-ethylhexanoate, tetrabutylammonium heptanoate, tetrabutylammonium hexanoate, tetrabutylammonium octanoate and tetrabutylammonium decanoate, or combinations thereof. Preferably the ionic liquid is tetrabutylammonium hexanoate.

Ionic liquids for use according to the present invention preferably have a melting point of 250 °C or less, more preferably 150 °C or less, still more preferably 100 °C or less, still more preferably 80 °C or less, and most preferably, the ionic liquid has a melting point below 30 °C. However, any compound that meets the criteria of being a salt (consisting of a cation and an anion) and which is liquid at the operating temperature and pressure of the process, or exists in a fluid state during any stage of the reaction, may be defined as an ionic liquid for the purposes of the present invention. Most preferably, the ionic liquid is chosen so as to be substantially immiscible with the hydrocarbon fluid, particularly where the hydrocarbon fluid comprises a liquid hydrocarbon.

Ionic liquids for use in the present invention are generally formed via metathesis reactions, an acid-base neutralization reaction or direct combination. Each of these reactions are considered to be well-known within the present field, and so it would be within the knowledge of the skilled person to select suitable starting materials as well as reaction conditions to produce the desired ionic liquid. In preferred embodiments, ionic liquids of the present invention are formed using an acidbase neutralization method. Such methods generally comprise combining a hydroxide- based ionic liquid, such as a quaternary ammonium hydroxide, and an acid, such as a carboxylic acid. In some examples, the carboxylic acid comprises a formula R¹-CO₂H, wherein R¹ is selected from a Ci to C20 branched or linear chain alkyl. Preferably, R¹ is selected from a C₂ to C14 linear or branched alkyl, more preferably a C₂ to Ci₂ linear or branched alkyl. Most preferably, R¹ is selected from hexyl, heptyl, octyl, 2-ethylhexyl and decyl, and combinations thereof.

In some embodiments, the hydroxide-based ionic liquid and acid are added in a stochiometric ratio, preferably at least 1 :1 ratio, as illustrated in Reaction Scheme 1 below. In some examples, the acid is present in a slight excess of the hydroxide-based ionic liquid, more preferably, the hydroxide-based ionic liquid and acid may be combined in a molar ratio of ratio of 1 :1 .5, preferably 1 :1 .2 and even 1 :1.1.

Reaction Scheme 1

In general, acid is added dropwise to the hydroxide-based ionic liquid whilst stirring at room temperature (25 °C). During the reaction, the hydroxide-based ionic liquid and acid may be mixed at a rate of 50 to 500 rpm, preferably from 100 to 300 rpm.

In some embodiments, the ionic liquid formed may be selected from tetrabutylammonium 2-ethylhexanoate ([TBA][2-ethylhex]), tetrabutylammonium heptanoate ([TBA][Hep]), tetrabutylammonium hexanoate ([TBA][Hex]), tetrabutylammonium octanoate (TBA][Octa]) or tetrabutylammonium decanoate ([TBA][Deca]).

Water produced as a by-product of the acid-base neutralisation process can be removed using standard techniques such as rotary evaporation, vacuum heating or distillation. It will be appreciated that it is environmentally friendly for the reaction by-product to be water, and also to avoid the unnecessary formation of halides - which has additional benefits as noted below. ln preferred embodiments, the ionic liquids formed are free of halides. At high temperatures and/or pressures, water may be hydrolyzed and acids, such as HCI, may formed in the presence of halides. Corrosion caused by these acids can be economically costly, both in terms of replacement parts and process down-time. Furthermore, when working with bromine or chlorine under ambient or near-ambient temperatures and pressures, there are significant difficulties and hazards that are associated with the corrosivity and toxicity of both bromine and chlorine vapours. In addition, bromine is known to oxidise many metals to their corresponding bromide salts, with anhydrous bromine being less reactive toward many metals than hydrated bromine. Dry bromine reacts vigorously with aluminium, titanium, mercury as well as alkaline earths and alkali metals forming metal bromide salts. Accordingly, the presence of halides can result in the damage or failure of plant equipment leading to increased costs and, in extreme cases, plant shutdown.

A sulfur salt is added to the above-mentioned ionic liquid in order to form activated sulfur compounds which comprise (poly)sulfide dianions (S²'_n). In preferred embodiments, the sulfur salt compounds are selected from a Group I or Group II alkali metal/ alkali earth metal sulfur compound. The Group I or Group II alkali metal/ alkali earth metal sulfur compound may be selected from Group I or Group II alkali metal sulfides, such as lithium sulfide (l_i₂S), sodium sulfide (Na₂S), potassium sulfide (K₂S), rubidium sulfide (Rb₂S), caesium sulfide (Cs₂S), beryllium sulfide (BeS) calcium sulfide (CaS), magnesium sulfide (MgS), strontium sulfide (SrS), barium sulfide (BaS) or a combination thereof. More preferably, the sulfur salt compound is a Group I alkali metal sulfide, most preferably the sulfur salt compound is selected from sodium sulfide (Na₂S) or potassium sulfide (K₂S). In some embodiments, an ionic liquid and sulfur salt are contacted with the mercury- containing hydrocarbon fluid feed concurrently, such that the active organic salt composition is formed in-situ. However, preferably, the active organic salt composition is formed by pre-mixing the ionic liquid and sulfur salt and is subsequently contacted with the mercury-containing hydrocarbon fluid feed.

It will be understood that as the amount of sulfur present in the active organic salt composition increases, the relative effectiveness of the composition formed increases, and so the amount of sulfur present in the active organic salt composition is not particularly limited. For example, sulfur salt may be added to the solubility limit of the selected ionic liquid. In some embodiments, the amount of sulfur present in the active organic salt composition may be up to 1500 ppm, preferably up to 2000 ppm, more preferably up to 2500 ppm, even more preferably up to 3500 ppm. In some embodiments, the active organic salt composition comprises sulfur in an amount of from 500 ppm to 1750 ppm by weight preferably 750 ppm to 1250 ppm by weight, more preferably from 850 ppm to 1150 ppm by weight.

In order to reduce the reaction time for forming the pre-mixed active organic salt composition, the ionic liquid and sulfur salt may be heated to a temperature of 40 to 100 °C, preferably from 60 to 80°C, such as 65 to 75°C and/or the ionic liquid and sulfur salt may be mixed at a rate of 100 to 1000 rpm, preferably 150 to 800 rpm, more preferably 200 to 400 rpm.

In practice, the active salt composition is completely formed when the composition turns dark greenish-blue after addition of the sulfur salt to the ionic liquid.

In preferred embodiments of the present invention, the active organic salt composition is free of halide ions. As discussed above, corrosion caused by the presence of halides can be economically costly, both in terms of replacement parts and process down-time. The process of the invention may be applied to substantially any hydrocarbon feed which comprises mercury, and which is liquid or gaseous under the operating conditions of the process. Thus, hydrocarbon fluids that may be processed according to the present invention include liquid hydrocarbons, such as liquefied natural gas; light distillates, e.g. comprising liquid petroleum gas, gasoline, and/or naphtha; natural gas condensates; middle distillates, e.g. comprising kerosene and/or diesel; heavy distillates, e.g. fuel oil; and crude oils. Hydrocarbon fluids that may be processed according to the present invention also include gaseous hydrocarbons, such as natural gas and refinery gas. Preferably the hydrocarbon fluid comprises a liquid hydrocarbon.

Mercury-containing hydrocarbon fluids processed according to the present invention may comprise from 1 part per billion (ppb) weight of mercury to 1 ,000,000 ppb weight of mercury, for instance 1 to 250,000 ppb weight of mercury; or 500 to 100,000 ppb weight of mercury. The mercury content of naturally occurring hydrocarbon fluids may take a variety of forms, and the present invention can be applied to the removal of elemental mercury, particulate mercury, organic mercury, in organic mercury or ionic mercury from hydrocarbon fluids. In one preferred embodiment, the mercury present is in the form of one or more of elemental, particulate or organic form. Still more preferably, the mercury is in elemental or organic form. Thus, in one embodiment, the mercury is in elemental form. In a further embodiment, the mercury is in organic form.

In some embodiments, the active organic salt composition and the liquid mercury- containing hydrocarbon fluid feed are contacted in a volume ratio of from 1 :1 to 1 :10,000, preferably 1 :500 to 1 :3000, more preferably 1 :1500 to 1 :2500. Alternatively, the active organic salt composition may be added to the mercury-containing hydrocarbon fluid feed in an amount so as to form an active organic salt composition to mercury molar ratio of from 0.5:1 to 3:1 , preferably from 1 :1 to 2:1. In particular, the active organic salt composition is added to the mercury-containing hydrocarbon fluid feed in an amount so as to form an active organic salt composition to mercury molar ratio of 1 :1 .

The active organic salt may be heated prior to contacting the mercury-containing hydrocarbon fluid feed. For example, the active organic salt composition is contacted with the mercury-containing hydrocarbon fluid feed at a temperature of from 0°C to 250°C, preferably from 0°C to 150°C; more preferably from 25°C to 150°C and most preferably from 25 to 80°C.

As discussed above, upon contact with the sulfur species present in the active organic salt composition, mercury within the hydrocarbon feed may form an intermittent mercury (II) cation (Hg²⁺) followed by complexing with poly(sulfide) dianions to form mercury (II) sulfide (HgS). HgS is a highly stable form of mercury which does not dissolve in either water or hydrocarbons. Upon aggregation with similar or dissimilar particles within the mixture, the hydrodynamic size of the particles exceeds the threshold for precipitation from solution and can then be subsequently removed.

Preferably, as a result of the process of the present invention, mercury is removed from the hydrocarbon fluid feed in the form of a mercury sulfide precipitate. Mercury (II) sulfide is found in two forms, cinnabar (alpha form) and metacinnabar (beta form), preferably mercury is removed as beta-mercury (II) sulfide (metacinnabar).

The presence of p-HgS can be determined using powder x-ray diffraction (PXRD). It is expected that peaks at 26.35°, 30.52°, 43.70°, 51 .75° and 54.24° would be observed for P-HgS corresponding to the diffraction planes of (111), (200), (220), (311) and (222) of the bulk p-HgS.

Following contact with the active organic salt composition, the mercury salt precipitate may be at least partially separated from the hydrocarbon fluid product by filtration means (such as the use of a membrane or ceramic filter), centrifugation, cyclone or gravity separation.

In addition, or alternatively, mercury may be at least partially separated from the hydrocarbon fluid product by gravity separation, air flotation and electrophoresis separation means. In order to reduce the time required for particulates of sufficient size to form and precipitate out of the hydrocarbon fluid product, the process may further comprise the addition of a flocculent to aid in removal of the mercury sulfide precipitate. Flocculants promote the agglomeration of the small particulates formed into a ‘floc’, thereby accelerating the point at which the particulates reach a size sufficient to precipitate out of the hydrocarbon fluid feed.

In some embodiments, the flocculant comprises a polymeric flocculant and more preferably the polymeric flocculant comprises a cationic or anionic polymer flocculant. Where the flocculant is selected from a cationic polymer flocculant, the polymer preferably comprises a quaternary ammonium, quaternary sulfonium or quaternary phosphonium groups. In particular, the cationic polymer flocculant may be selected from a cationic polyacrylamide flocculant or one or more of methacryloyloxyethyl trimethylammonium chloride (DMC), acryloyloxyethyl trimethylammonium chloride (DAC), diallyldimethylammonium chloride (DADMAC), [2-(acryloyloxy)ethyl]trimethylammonium chloride (AETAC), and acrylamide propyl trimethyl ammonium chloride (APTAC).

Where the flocculant is selected from an anionic polymer flocculant, the polymer preferably comprises a carboxylate or sulphonate functional group. Preferably, the anionic polymer flocculant may be selected from poly(acrylic acid), poly(acrylamide) or poly(styrene sulfonic acid) (PSSA).

The process of the present invention can remove mercury in an amount of greater than 40 %, preferably greater than 50 %, more preferably greater than 60 %, even more preferably greater than 70 % and most preferably greater than 80 %, by weight as compared to the amount of mercury present in the mercury-containing hydrocarbon fluid feed. Without being bound by theory, it is believed that that presence of an ionic liquid enables translocation of the activated sulfur compounds, increasing interaction with the dissolved mercury in both the hydrocarbon (oleophilic) and aqueous (hydrophilic) phases of the hydrocarbon feed. Thereby increasing the amount of mercury extracted. The mercury content of the hydrocarbon feed can be determined using various conventional analytical techniques known in the art, such as cold vapor atomic absorption spectroscopy (CV-AAS), inductively coupled plasma atomic emission spectroscopy (ICP- 20 AES), X-ray fluorescence, or neutron activation. If the values produced by the above- mentioned methods differ, the mercury content of the hydrocarbon feed is determined in accordance with ASTM D 6350.

In a second aspect of the present invention, there is provided a process for producing an active organic salt composition for use in a mercury removal process as defined above, wherein the process comprises the steps of:

(i) providing a basic ionic liquid having a neutral cation and a basic anion of formula [Cat⁺][Bas'];

(ii) providing a carboxylic acid of formula R¹-CO₂H, wherein R¹ is Ci to C₂o branched or linear chain alkyl;

(iii) combining the basic ionic liquid and carboxylic acid to produce an ionic liquid of formula [Cat⁺][ R¹-CO₂'] and water;

(iv) providing a sulfur salt and adding to the ionic liquid formed in step (iii); and

(v) obtaining an active organic salt composition.

In this embodiment of the invention, the ionic liquid of the active organic salt composition may be formed via an acid-base neutralization reaction, as described above.

The ionic liquid cation, [Cat⁺], may be any of the ionic liquid cations described above, and those cations described as preferred above are also preferred in this embodiment of the invention. [Bas'] may be selected from any ionic liquid anion able to readily exchange with a carboxylate anion, for example [Bas'] may be selected from a hydroxide. As discussed above, the carboxylic acid comprises a formula R¹-CO₂H, wherein R¹ is selected from Ci to C₂o branched or linear chain alkyl. Preferably, R¹ is selected from a C₂ to C14 linear or branched alkyl, more preferably a C₂ to Ci₂ linear or branched alkyl. Most preferably, R¹ is selected from hexyl, heptyl, octyl, 2-ethylhexyl and decyl, and combinations thereof.

In step iii) of the process, the ionic liquid and carboxylic acid may be present in a stoichiometric ratio. Preferably, the carboxylic acid is present in a slight excess with respect to the ionic liquid, for example the ionic liquid and carboxylic acid may be combined in a molar ratio of ratio of 1 : 1 .5, preferably 1 :1.2 and even 1 :1.1.

In some embodiments, the step of combining the basic ionic liquid and carboxylic acid to produce an ionic liquid of formula [Cat⁺][ R¹-CO₂ ^_], may be accelerated by heating the basic ionic liquid and/or carboxylic acid prior to contacting. Alternatively, once combined, the basic ionic liquid and carboxylic acid may be heated in order to reduce the reaction time for forming an ionic liquid of formula [Cat⁺][ R¹-CO₂ ^_] and water (as defined in step (iii)). Preferably, step (iii) is performed at a temperature of 10 to 50°C, such as 15 to 30°C, for example 20 to 25°C.

Alternatively or in addition to heating the basic ionic liquid and/or carboxylic acid, step (iii) may further comprise stirring in order to increase the interaction between the basic ionic liquid and carboxylic acid, thereby reducing the required reaction time for forming an ionic liquid of formula [Cat⁺][ R¹-CO₂ ^_] and water. For example, step (iii) may be performed whilst stirring at a rate of from 50 to 500 rpm, more preferably 100 to 300 rpm.

The water formed in step (iii) of the process may be at least partially removed prior to adding a sulfur salt to the ionic liquid formed. Water produced as a by-product of step (iii) can be removed using standard techniques within this field such as, rotary evaporation, vacuum heating or distillation. With regards to step (iv), the sulfur salt is preferably selected from a Group I or Group II alkali metal/ alkali earth metal sulfur compound. The Group I or Group II alkali metal/ alkali earth metal sulfur compound may be selected from Group I or Group II alkali metal sulfides, such as lithium sulfide (Li₂S), sodium sulfide (Na₂S), potassium sulfide (K₂S), rubidium sulfide (Rb₂S), caesium sulfide (Cs₂S), beryllium sulfide (BeS) calcium sulfide (CaS), magnesium sulfide (MgS), strontium sulfide (SrS), barium sulfide (BaS) or a combination thereof. More preferably, the sulfur salt compound is a Group I alkali metal sulfide, most preferably the sulfur salt compound is selected from sodium sulfide (Na₂S) or potassium sulfide (K₂S). It has been surprisingly found that significantly increased amounts of bulk mercury can be extracted from a mercury-containing hydrocarbon fluid feed when the sulfur source is selected from a sulfur salt which forms (poly)sulfide dianions (S^2- _n) when contacted with the above mentioned ionic liquids.

In some embodiments, the amount of sulfur present in the active organic salt composition formed may be up to 1500 ppm, preferably 2000 ppm, more preferably 2500 ppm, even more preferably up to 3500 ppm. In some embodiments, the active organic salt composition comprises sulfur in an amount of from 500 ppm to 1750 ppm by weight preferably 750 ppm to 1250 ppm by weight, more preferably from 850 ppm to 1150 ppm by weight.

In order to reduce the reaction time for forming the active organic salt composition, the ionic liquid formed in step (iii) and sulfur salt may be heated to a temperature of 25 to 100°C, such as 40 to 90°C, for example 60 to 80°C and/or the ionic liquid and sulfur salt may be mixed at a rate of 100 to 1000 rpm, preferably 100 to 500 rpm, more preferably 200 to 400 rpm.

In a third aspect of the present invention, there is provided the use of an active organic salt composition as defined herein for the removal of mercury from a mercury-containing hydrocarbon fluid.

In a fourth aspect of the present invention, there is provided the use of an active organic salt composition as defined herein as a replacement for a mercury removal unit. The active organic salt of the present invention is capable of removing at least 50% of the mercury present in the hydrocarbon stream. Preferably, the active organic salt composition is capable of removing at least 80% of the mercury present in the hydrocarbon stream. More preferably, the active organic salt composition is capable of removing at least 85%, more preferably at least 90%, and even more preferably at least 95% of the mercury present in the hydrocarbon stream. In some embodiments of the invention, the active organic salt composition is capable of removing at least 96%, 97%, 98% and even at least 99% of the mercury present in the hydrocarbon stream.

In a fifth aspect of the present invention there is provided the use of an active organic salt composition as defined herein to reduce operating process damage to a mercury removal unit.

The present invention will now be described, by way of example only, with reference to the accompanying Figures, in which:

Figure 1 is a flow cart illustrating a process of removing mercury from a mercury- containing hydrocarbon fluid feed, in accordance with the present invention;

Figure 2 shows a bar chart illustrating the amount of Hg° remaining in an onshore condensate following treatment with various mercury extracting agents;

Figure 3 shows a bar chart illustrating the amount of HgCI₂ remaining in an onshore condensate following treatment with various mercury extracting agents;

Figure 4 shows a bar chart illustrating the amount of Hg° remaining in an offshore condensate following treatment with various with mercury extracting agents;

Figure 5 shows a bar chart illustrating the amount of HgCI₂ remaining in an offshore condensate following treatment with various with mercury extracting agents.

Figure 1 illustrates an embodiment of a process according to the present invention. In this particular embodiment, an active organic salt composition (2), as defined above, is contacted with a mercury-containing hydrocarbon fluid feed (4) extracted from an underground reservoir. The mercury-containing hydrocarbon fluid feed (4) may comprise a mixture of produced water and mercury-containing natural gas. Of course, in an alternative embodiment, the active organic salt composition may be injected directly into the underground reservoir. Upon reaction with the active organic salt composition, mercury salt precipitate is formed and may be at least partially separated from the hydrocarbon fluid product by filtration means (such as the use of a membrane or ceramic filter), centrifugation, cyclone, gravity separation, air flotation or electrophoresis separation means.

The reduced mercury hydrocarbon feed may subsequently be transferred to a separator (6), wherein the reduced mercury hydrocarbon feed is separated into a gas feed (8) (consisting primarily of Ci to C4 alkanes), a liquid feed (10) (comprising C5 to C₈ alkanes) and solids (12).

Solids (12) present in the reduced mercury hydrocarbon feed may be separated by commonly used techniques within this field, including filtration means, centrifugation, cyclone or gravity separation.

The gaseous feed formed (8) is then transferred to a mercury removal unit (MRU) (14) in order to further reduce the concentration of any mercury species remaining following treatment with the active organic salt composition (2). The mercury removal units may comprise fixed bed adsorbents such as activated carbon, zeolite and alumina, through which the gaseous feed can flow, removing at least a portion of mercury present. In alternative embodiments, the presence of MRU following treatment with the active organic salt composition will not be required.

The gaseous feed can be further treated to meet industry standards by undergoing dewatering (16) and acid gas removal treatments (18) to at least partially remove H₂S and/or CO₂ present.

Upgrading (20) of the semi-refined gaseous products in order to produce fuels may further be required. These upgrading processes may comprise one or more of catalytic reforming, isomerisation, fuel blending, hydrocracking and fluid catalytic cracking. Following the upgrading process, the mixture of fuels may optionally be transferred to a further mercury removal unit (MRU) (22), if further reduction of mercury content is required.

The treated gas is then cooled using a heat-exchanger, such as a cold box (24), and undergoes low-temperature fractionation, for example cascade refrigeration using propylene and ethylene as refrigerants. Non-condensable gases, such as hydrogen, nitrogen, and carbon monoxide and relatively pure methane are first separated from the higher hydrocarbons present. At the next stage, C₂ hydrocarbons (ethylene and ethane) are separated from the remaining higher hydrocarbons (26). The separated Ci and C₂ products (28) may be further processed. For example, ethylene (30) separated may undergo further mercury removal treatment by passing through a MRU (32) to produce a final ethylene product (34). Similarly, isolated methane may be used to form ammonia (36) via a Haber process. The ammonia formed may be further treated using a mercury removal unit (MRU) (38) to produce a final ammonia product (40).

The liquid feed (10) may be separated into crude oil (42), a condensate feed (44) (predominantly comprising Cs to C₈ alkanes) and a produced water feed (46).

The produced water feed (46) may optionally be transferred to a further mercury removal unit (MRU) (48), if further reduction of mercury content is required. The treated produced water feed may then be either disposed of or recycled (as discussed further below).

The condensate feed (44) may also optionally be transferred to a further mercury removal unit (MRU) (50) and/or contacted with an active organic salt composition (52), as defined above, if further reduction of mercury content is required.

The treated condensate can then be separated (54) into hydrocarbon products for example using flash distillation or fractional distillation. The stream collected from the bottom of the distillation tower is heavy naphtha fuel (56). The separated naphtha fuel (56) may optionally be transferred to a further mercury removal unit (MRU) (58), if further reduction of mercury content is required, to produce a final naphtha fuel product (60).

Following the further mercury removal treatment (58), where present, the reduced mercury naphtha formed may undergo additional refining/upgrading processes, including hydrotreating processes to reduce the amount of sulfur present, catalytic cracking and/or hydrocracking to reduce the presence of larger hydrocarbon compounds, and optionally blending with other streams (62), in order to produce a fuel meeting all of the requisite chemical, physical, economic and inventory requirements of the required hydrocarbon product. In addition, the refined/upgraded product may further undergo treatment in a mercury removal unit (MRU) (64), if necessary. The hydrocarbon product may then be separated (66) into hydrocarbon products, for example using flash distillation or fractional distillation.

With regards to the crude oil (42) separated, further processing in a desalter (68) is performed, wherein small inorganic salts, such as NaCI, CaCI₂ and MgCI₂ are removed from the crude oil by extraction into an aqueous phase. In some embodiments, wastewater from the produced water feed (46) may be used to remove inorganic salts from crude oil.

The treated crude oil may then be combined with the treated condensate and separated (54) into hydrocarbon products for example using flash distillation or fractional distillation.

Alternatively or in addition to the above, in some embodiments the active organic salt composition may be contacted with the fluid feed directly prior to the feed entering the mercury removal unit. In this way, the occurrence of premature saturation of mercury adsorbents within the mercury removal units can be reduced. EXAMPLES

Example 1

Removal of mercury from an onshore natural gas condensate

In the present examples, the effectiveness of four types of mercury extracting agent, in particular aqueous Na₂S, aqueous K₂S, TMT15 (C₃N₃S₃Na₃) and (NH^S (all known in the art) and active organic salt compositions in accordance with the present invention, were compared. The mercury extracting agent in each example was added to an onshore condensate in a mass ratio of 1 :1 with regards to the amount of mercury present within the condensate. The selected onshore condensate feedstock comprised approximately 1000 pg/kg of Hg° or approximately 1000 pg/kg of HgCI₂.

The active organic salt compositions of the present invention that were analysed are provided in Table 1 below. The sulfur source added in each example was Na₂S, K₂S TMT15 (C₃N₃S₃Na₃) and (NH^S. In addition, [N4444][2-ethylhexanoate] was selected as a suitable ionic liquid. The samples were prepared by adding aqueous solutions of the sulfur salt to [N4444][2-ethylhexanoate] whilst stirring until the concentration of the sulfur salt in the mixture reached 1000 ppb wt and a slightly darker colour compared to the neat ionic liquid was observed. The mixture was then shaken for between 15 and 20 second at room temperature (25 °C) to form the active organic salt compositions.

Table 1

In each example the mercury extracting agent and onshore condensate were combined before shaking for 15 to 20 seconds at room temperature (25 °C. The shaking was then stopped, and the precipitated mercury salt separated from the condensate and ionic liquid by centrifuging techniques . In particular, the samples were centrifuged at 4,400 rpm for 15 to 20 minutes. This step was repeated three times. The majority of the ionic liquid and condensate was then decanted from the centrifuged samples leaving only a small volume containing the precipitated mercury salt suspended therein. The suspension was then air dried to remove any remaining liquid.

The amount of Hg° (pg/kg) remaining in the onshore condensate following treatment with each of the mercury extracting agents is illustrated in Figure 2 and Table 2 below.

Table 2

It is immediately apparent that the active organic salt compositions falling within the scope of the present invention provide superior extraction of elemental mercury from the onshore condensate. In particular, following treatment with the comparative extracting agents, the amount of Hg° remaining in the condensate ranged from 262.29 to 398.83 pg/kg. In complete contrast, use of the active organic salt compositions reduced the amount of Hg° present in the onshore condensate to between 180.56 and 265.36 pg/kg. Similarly, the amount of HgCI₂ (pg/kg) remaining in the onshore condensate following treatment with each of the mercury extracting agents is illustrated in Figure 3 and Table 3 below.

Table 3

Once again, the amount of HgCI₂ present in the onshore condensate was notably lower following treatment with the active organic salt composition, compared with Na₂S, K₂S,TMT15 and (NH₄)₂S.

Example 2

Removal of mercury from an offshore natural gas condensate

In the present examples an offshore condensate comprising approximately 1000 pg/kg of Hg° or approximately 1000 pg/kg of HgCI₂ was treated with mercury extracting agents as defined in Example 1 .

The amount of Hg° (pg/kg) remaining in the offshore condensate following treatment with each of the mercury extracting agents is illustrated in Figure 4 and Table 4 below. Table 4

With regards to treating offshore condensates, use of active organic salt compositions in accordance with the present invention was significantly more effective at reducing the elemental mercury present within the offshore condensate (155.12 to 193.99 pg/kg) compared to Na₂S, K₂S,TMT15 and (NH₄)₂S (229.96 to 529.55 pg/kg).

The amount of HgCI₂ (pg/kg) remaining in the offshore condensate following treatment with each of the mercury extracting agents is illustrated in Figure 5 and Table 5 below. Table 5

The use of an active organic salt composition as defined in the present claims was again significantly more effective in reducing the amount of HgCI₂ present in the offshore condensate. In particular, the active organic salt compositions reduced the amount of HgCI₂ to from 152.04 to 295.71 pg/kg, whereas significantly higher amounts of HgCI₂ remained when Na₂S, K₂S, TMT15 and (NH^S were selected as the mercury extracting agent (544.19 to 683.10 pg/kg).

Example 3

Controlling the formation of 6-HgS solids

As discussed above, as a result of the process of the present invention, mercury is removed from the hydrocarbon fluid feed in the form of a mercury sulfide precipitate, preferably as beta-mercury (II) sulfide (metacinnabar).

Following contact with the active organic salt composition, the mercury salt precipitate formed may be at least partially separated from the hydrocarbon fluid product by filtration means (such as the use of a membrane or ceramic filter), centrifugation, cyclone or gravity separation.

It is considered readily apparent that the amount of p-HgS solids formed (as a black precipitate) is dependent, at least in part, on the concentration of active organic salt composition added and the initial concentration of mercury in the hydrocarbon fluid feed.

The formation of P-HgS precipitates formed in accordance with the present invention may be verified using powder X-ray diffraction (PXRD), wherein the samples are expected to produce characteristic peaks at 26.35°, 30.52°, 43.70°, 51 .75° and 54.24°

It was observed that the precipitate comprised irregular shaped aggregates of various sizes. It is believed that different particle size distributions were formed a result of different rates of particle growth (aggregation) via Ostwald ripening in different ionic liquids selected. Accordingly, the present invention may be tailored to increase the particle size of the mercury precipitate formed and thereby facilitate the removal of mercury from a mercury- containing hydrocarbon fluid feed.

Accordingly, the present invention provides an improved method of extracting mercury from mercury-containing hydrocarbon fluid feeds. As the defined active organic salt compositions are more adept at extracting mercury, the use of such compositions is more effective and reliable at producing hydrocarbon products which meet industry implemented regulations when the concentration of mercury in the feed varies. Furthermore, given that the use of active organic salt compositions as defined herein further reduces the amount of mercury present in the treated hydrocarbon feed compared to other known extracting methods/agents, the requirement of multiple or repeated extraction steps in order to meet the required mercury concentration is avoided. In this way, use of organic salt compositions as defined herein provides a more time and cost- effective method of processing hydrocarbon feedstocks.

Claims

1 . A process for removing mercury from a mercury containing hydrocarbon fluid feed, the process comprising the steps of:

[Cat⁺][X-] wherein: [Cat⁺] represents one or more cationic species; and

[X-] represents one or more alkyl carboxylic acid species; and

2. A process according to Claim 1 , wherein [X-] represents one or more carboxylic acid species of formula:

[R¹-CO₂]- wherein R¹ is selected from Ci to C20 branched or linear chain alkyl.

3. A process according to Claim 2, wherein R¹ is selected from C₂ to C14 linear or branched alkyl, preferably C₂ to Ci₂ linear or branched alkyl .

4. A process according to Claim 2 or Claim 3, wherein R¹ is selected from hexyl, heptyl, octyl, 2-ethylhexyl and decyl, and combinations thereof.

5. A process according to any one of the preceding claims, wherein [Cat⁺] comprises a cation selected from the group consisting of: ammonium, azaannulenium, azathiazolium, benzimidazolium, benzofuranium, benzotriazolium, borolium, cinnolinium, diazabicyclodecenium, diazabicyclononenium, diazabicyclo- undecenium, dithiazolium, furanium, imidazolium, indazolium, indolinium, indolium, morpholinium, oxaborolium, oxaphospholium, oxazinium, oxazolium, iso- oxazolium, oxothiazolium, pentazolium, phospholium, phosphonium, phthalazinium, piperazinium, piperidinium, pyranium, pyrazinium, pyrazolium, pyridazinium, pyridinium, pyrimidinium, pyrrolidinium, pyrrolium, quinazolinium, quinolinium, /so-quinolinium, quinoxalinium, selenozolium, sulfonium, tetrazolium, /so-thiadiazolium, thiazinium, thiazolium, thiophenium, triazadecenium, triazinium, triazolium, and /so-triazolium.

6. A process according to Claim 5 wherein [Cat⁺] is selected from the group consisting of:

wherein: R^a, R^b, R^c, R^d, R^e, R^f and R⁹ are each independently selected from hydrogen, a Ci to C30, straight chain or branched alkyl group, a C3 to C₈ cycloalkyl group, or a C₈ to C10 aryl group, wherein said alkyl, cycloalkyl or aryl groups are unsubstituted or may be substituted by one to three groups selected from: Ci to Ce alkoxy, C₂ to C12 alkoxyalkoxy, C3 to C₈ cycloalkyl, Ce to C10 aryl, -CN, -OH, -SH, - NO₂, Ce to C10 aryl and C7 to C10 alkaryl, -CO₂(Ci to Ce)alkyl, - OC(O)(Ci to Ce)alkyl, or any two of R^b, R^c, R^d, R^e and R^f attached to adjacent carbon atoms form a methylene chain -(CH₂)q- wherein q is from 3 to 6.

7. A process according to any one of Claims 1 to 5, wherein the cation is selected from the group consisting of:

[N(R^a)(R^b)(R^c)(R^d)]⁺, [P(R^a)(R^b)(R^c)(R^d)]⁺, and [S(R^a)(R^b)(R^c)]⁺, wherein: R^a, R^b, R^c and R^d are as defined in Claim 6.

8. A process according to Claim 7, wherein [Cat⁺] is selected from:

[N(R^a)(R^b)(R^c)(R^d)]⁺, wherein R^a, R^b, R^c and R^d are each independently selected from Ci to C₈, straight or branched chain, alkyl.

9. A process according to Claims 7 and 8, wherein R^a, R^b, R^c and R^d are the same, and optionally selected from Ci to C₈ straight chain alkyl (methyl, ethyl, n-propyl, n-butyl, n-pentyl, n-hexyl, n-heptyl, n-octyl), such as C₂ to Ce alkyl (ethyl, n-propyl, n-butyl, n-pentyl, n-hexyl).

10. A process according to any one of Claims 1 to 5 and 7 to 9, wherein [Cat⁺] is tetrabutylammonium.

11. A process according to any one of Claims 1 to 5 and 7 to 10, wherein the ionic liquid [Cat⁺][X^_] is selected from one or more of tetrabutylammonium 2- ethylhexanoate, tetrabutylammonium heptanoate, tetrabutylammonium hexanoate, tetrabutylammonium octanoate and tetrabutylammonium decanoate, or combinations thereof; preferably wherein the ionic liquid is tetrabutylammonium hexanoate.

12. A process according to any one of Claims 1 to 11 , wherein the ionic liquid has a melting point of 250°C or less, preferably 100°C or less, and more preferably 30°C or less.

13. A process according to any one of Claims 1 to 12, wherein the ionic liquid is formed via an acid-base neutralization reaction.

14. A process according to any one of Claim 1 to 13, wherein the ionic liquid is free of halide ions.

15. A process according to any one of Claims 1 to 14, wherein the sulfur salt is a metal salt.

16. A process according to Claim 15, wherein the metal salt is an alkali metal salt (Group I metal salt).

17. A process according to Claim 16, wherein the metal salt is selected from sodium sulfide and potassium sulfide.

18. A process according to any one of Claims 1 to 17, wherein the active organic salt composition is formed by pre-mixing the ionic liquid and sulfur salt.

19. A process according to Claim 18, wherein the pre-mixed ionic liquid and sulfur salt is heated to a temperature of 60 to 80°C, such as 65 to 75°C.

20. A process according to Claim 18 or Claim 19, wherein the pre-mixed ionic liquid and sulfur salt is mixed at 100 to 1000 rpm, preferably 200 to 400 rpm.

21 . A process according to any one of Claims 1 to 20, wherein the active organic salt composition comprises sulfur in an amount of up to 2000 ppm weight.

22. A process according to any one of Claims 1 to 21 , wherein the active organic salt composition is free of halide ions.

23. A process according to any one of Claims 1 to 22, wherein the mercury-containing hydrocarbon fluid feed comprises one or more of:

(i) a liquefied natural gas;

(ii) a light distillate comprising liquid petroleum gas, gasoline, and/or naphtha;

(iii) a natural gas condensate;

(iv) a middle distillate comprising kerosene and/or diesel;

(v) a heavy distillate; and

(vi) a crude oil.

24. A process according to any one of Claims 1 to 23, wherein the mercury concentration in the mercury-containing hydrocarbon fluid feed is in the range of from 1 to 1 ,000,000 parts per billion weight; such as from 1 to 250,000 parts per billion weight.

25. A process according to any one of Claims 1 to 24, wherein the mercury-containing hydrocarbon fluid feed comprises at least one of elemental mercury, particulate mercury, organic mercury, inorganic mercury, or ionic mercury.

26. A process according to any one of Claims 1 to 25, wherein the active organic salt composition and the liquid mercury-containing hydrocarbon feed are contacted in a volume ratio of from 1 :1 to 1 :10,000, preferably 1 :500 to 1 :3000, more preferably 1 :1500 to 1 :2500.

27. A process according to any one of Claims 1 to 26, wherein the active organic salt composition is contacted with the mercury-containing hydrocarbon fluid feed at a temperature of from 0°C to 250°C, preferably from 0°C to 150°C; more preferably from 25°C to 150°C and most preferably from 25 to 80°C.

28. A process according to any one of Claims 1 to 27, wherein the active organic salt composition is contacted with the mercury containing hydrocarbon feed upstream of a mercury removal unit.

29. A process according to any one of Claims 1 to 28, wherein the process does not comprise a mercury removal unit.

30. A process according to any one of Claims 1 to 29, wherein the mercury is removed as a mercury sulfide precipitate; and preferably beta-mercury (II) sulfide (metacinnabar).

31. A process according to Claim 30, wherein the mercury sulfide precipitate is removed by way of one or more of gravity separation, centrifuging, filtering, air flotation and electrophoresis.

32. A process according to Claim 30 or Claim 31 wherein a flocculent is used to aid in removal of the mercury sulfide precipitate; preferably wherein the flocculant comprises a polymeric flocculant and more preferably wherein the polymeric flocculant comprises a cationic or anionic polymer flocculant.

33. A process for producing an active organic salt composition for use in the process according to any one of Claims 1 to 32, the process comprising the steps of:

(i) providing a basic ionic liquid having a neutral cation and a basic anion of formula [Cat⁺][Bas-];

(iii) combining the basic ionic liquid and carboxylic acid to produce an ionic liquid of formula [Cat⁺][ R¹-CO₂ ^_] and water; (iv) providing a sulfur salt and adding to the ionic liquid formed in step (iii); and

(v) obtaining an active organic salt composition.

34. A process according to Claim 33, wherein in step (iii), the acid is added in excess, such as a ratio of 1 : 1 .5, preferably 1 : 1 .2 and even 1 :1.1.

35. A process according to Claim 33 or Claim 34, wherein step (iii) is performed at a temperature of 10 to 50°C, such as 15 to 30°C, for example 20 to 25°C.

36. A process according to any one of Claims 33 to 35, where step (iii) is performed whilst mixing, such as at a rate of 50 to 500 rpm, more preferably 100 to 300 rpm.

37. A process according to any one of Claims 33 to 36, wherein the water is removed after step (iii) and prior to step (iv).

38. A process according to any one of Claims 33 to 37, wherein the sulfur salt is a metal sulfide, such as an alkali metal sulfide (for example sodium or potassium sulfide).

39. A process according to any one of Claims 33 to 38, wherein step (iv) is performed at a temperature of 25 to 100°C, such as 40 to 90°C, for example 60 to 80°C.

40. A process according to any one of Claims 33 to 39, where step (iv) is performed whilst stirring, such as at a rate of 100 to 500 rpm, more preferably 200 to 400 rpm.

41. Use of an active organic salt composition as described in any one of Claims 1 to 40 for the removal of mercury from a mercury-containing hydrocarbon fluid.

42. Use of an active organic salt composition as described in any one of Claims 1 to 40 as a replacement for a mercury removal unit.

43. Use of an active organic salt composition as described in any one of Claims 1 to 40 to reduce operating process damage to a mercury removal unit.