Composition, Process And Method For Treatment Of Liquid Petroleum Products Having High Concentrations Of Sulfur Compounds

Description

PRIORITY CLAIM

The present application claims the benefit of U.S. Provisional Application 63/702,030 filed Oct. 1, 2024, the specification of which is incorporated by reference in its entirety herein.

TECHNICAL FIELD

This disclosure relates to methods and processes for treatment of liquid petroleum products such as crude oil having high concentrations of sulfur compounds such as hydrogen sulfide.

BACKGROUND

Hydrogen sulfide is often encountered in drilling, production, storage, transport, and processing of crude oil. This can include the initial crude oil product extracted as well as waste water that can be associated with crude oil production. Hydrogen sulfide can be undesirable and present processing problems. It can react with other hydrocarbons or fuel system components. Hydrogen sulfide is highly corrosive and even in low concentration, has a noxious odor. At elevated concentrations hydrogen sulfide gas can cause significant health and environmental risks. Crude oil production in in oil fields having elevated hydrogen sulfide concentration levels can be accompanied by elevated corrosion of well bore and other equipment as well as expenses associated with environmental mitigation as well as materials handling and pipeline equipment.

Generation of hydrogen sulfide can be continuous or sporadic throughout the drilling and production of crude oil. Thus, a process and method that can reduce hydrogen sulfide present as vapor and/or as solubilized material in crude oil is desirable. It is also desirable that the one which accomplishes sulfur reduction, in whole or in part, by dissociation and/or mitigation. It is also desirable that the process and method be one that can be implemented at or near the well bore. It is also desirable that the process and method be one that can produce low sulfur crude oil in a continuous manner proximate to the well bore.

SUMMARY

Disclosed herein is a method and process for treating crude oil, particularly extracted crude oil at or proximate to the well bore to reduce sulfur content, particularly sulfur content present as hydrogen sulfide in the crude oil process stream being extracted and produced. In certain specific embodiments, the process and method as disclosed herein can occur subsequent to the extraction of one or more of water and gaseous components present in the process stream that can be associated with drilling and extraction operations. In certain embodiments the process can be employed prior to sales metering steps associated with drilling and extraction operations.

In certain embodiments the method as disclosed herein includes the step of contacting a process stream containing crude oil having an elevated sulfur content present, at least in part as hydrogen sulfide, with an effective amount of a treatment composition composed of at least one polar protic solvent and an inorganic strong base such as a hydroxide material. The strong base component such as inorganic hydroxide can be present in an effective molar ratio of solvent to an inorganic strong base component.

In certain embodiments, the treatment composition can be composed of at least one polar protic solvent and an inorganic strong base component present in a defined molar ratio of solvent to the inorganic strong base component. Where desired or required, the inorganic strong base component can be composed in whole or in part of an inorganic hydroxide component. The material can be anhydrous if desired or required. In certain embodiments, the molar ratio between 1.5 and 2.5 M.

In certain embodiments, the treatment composition will have an initial pH greater than 12.

In certain embodiments, the treatment composition contacting step can occur subsequent to removal of water and/or gaseous components present in the crude oil if desired or required. In certain embodiments, treatment composition can be brought into contact with the crude oil process stream downstream of water and/or gaseous compound operations and mechanisms. The treatment contacting step can occur at a location either immediately downstream of degassing and/or dewatering operations or located a measured distance from such operations. In certain embodiments, the contacting step proceeds for an interval sufficient to convert hydrogen sulfide present in the crude oil material to sulfate compounds.

In certain embodiments, the crude oil in the process stream can contain sulfur compounds such as hydrogen sulfide, sulfide aromatic compounds and the like at a level greater than 1000 ppm.

In certain embodiments, the treatment composition as disclosed herein can be added directly to the crude oil in the process stream. In certain embodiments, the treatment composition as disclosed herein can be admixed with a suitable portion of crude oil material that contains less than 0.5% aromatic sulfide compounds, (sometimes referred to as sweet crude) prior to introduction into the crude oil process stream to be treated. The resulting sweet crude/treatment composition admixture can then be introduced into contact with crude oil having an aromatic sulfide compound content greater than 0.1% by weight. The resulting product will be crude oil having a sulfide content between 0 and 1000 ppm.

Also disclosed is a well field crude oil processing system that comprises at least one pipe or conduit having an upstream end and a downstream end and a crude oil stream passing therethrough. The well field crude oil processing stream is configured such that crude oil treated enters into an initial region of the well field crude oil processing system. The initial region of the well filed crude oil system is proximate to and in fluid communication with the upstream end of the pipe or conduit of the well field pipe line system. Crude oil introduced into the initial region of the well field crude oil processing system can have a sulfur content greater than 0.005% with the sulfur content comprising at least one of hydrogen sulfide, aromatic sulfides and elemental sulfur.

The final region of the well field crude oil processing system as disclosed herein can be placed in fluid communication with the well filed pipe system and can introduce treated crude oil into the well filed crude oil pipe system that has a sulfur content less than 0.005% and further comprises a polar protic solvent present in an amount between 0.2-molar and 5 molar. The well field crude oil processing system as disclosed herein can be located in the oil processing system downstream of the well head and upstream of at least one sales metering device.

These and other aspects of the present disclosure are disclosed in the following detailed description of the embodiments, the appended claims and the accompanying figures.

BRIEF DESCRIPTION OF THE DRAWINGS

The invention is best understood from the following detailed description when read in conjunction with the accompanying drawings. It is emphasized that, according to common practice, the various features of the drawings are not to-scale. On the contrary, the dimensions of the various features are arbitrarily expanded or reduced for clarity.

FIG. 1 is process diagram of an embodiment of the crude oil treatment method and process as disclosed herein;

FIG. 2 is a diagrammatic depiction of an embodiment of the process as disclosed herein; and.

FIG. 3 is a diagrammatic depiction of the of FIG. 1 in which sweet crude is admixed with the treatment composition.

DETAILED DESCRIPTION

Disclosed herein is a method and process for treating petrochemical feedstock materials such as crude oil, particularly extracted crude oil at or proximate to the well head. In certain embodiments, the crude oil material suitable for treatment as disclosed can have a water content less than 0.005% by weight or 5 ppm. In certain specific embodiments the process and method as disclosed herein can occur subsequent to separation of natural gas and/or water from the crude oil component. In certain embodiments the crude oil component can be single-component crude in which substantial portions of water and/or natural gas have been removed as by separation or extraction. In well head operations, such removal can be accomplished by one or more suitable three-part extraction units.

Also disclosed is a device and apparatus that can provide effective delivery of treatment material to accomplish effective treatment of crude oil process streams and materials.

It is contemplated that the process and method as disclosed herein can be employed on crude oil feed stock material to reduce or eliminate sulfide compound(s) in the crude oil material. The method as disclosed herein can be efficaciously employed to reduce sulfide contamination in crude oil material having sulfur levels greater than 0.001% by weight. More particularly, the method and process as disclosed can be employed in crude oil feed stock having sulfur levels greater than 0.005% by weight, greater than 1.0% by weight, greater than 1.5% by weight, greater than 2.0% by weight, greater than 2.5% by weight, greater than 3.0% by weight.

Crude oil having a sulfur content greater than 0.005% by weight can be classified as sour crude. Sour gas can contain greater than 4 ppm hydrogen sulfide. The sulfur content in the crude oil process stream can exist in the form of free elemental sulfur, hydrogen sulfide gas, aromatic sulfur compounds and various other sulfur compounds, including but not limited to, sulfide, disulfides, mercaptans, thiophenes, benzothiophenes, and the like. Each crude material or gas may have different amounts or different types of sulfur compounds, but typically the proportion, complexity and stability of the sulfur compounds are greatest in heavier crude oil fractions.

In the United States, approximately 60% of extracted crude is classified as sour crude and is laced with sulfur-containing compounds and vapor phase gases. The sulfur containing compound can include but are not limited to compounds present as hydrogen sulfide. Sulfur-containing compounds such as hydrogen sulfide gases are undesirable for the production and refinement of crude oil materials and can pose hazards to the health and safety of field personnel and to the environment. In addition, sulfur-containing materials such as hydrogen sulfide can be extremely corrosive to the crude oil transfer pipeline as well as other refinement assets. Sour crude is difficult to handle and can be refined into petroleum and related petroleum products only at elevated cost relative to sweet crude material in part because the cracking catalyst material employed in petroleum refinement processes is unable to process or separate the sulfide vapor and any soluble sulfur from the resulting refined petroleum. Gaseous hydrogen sulfide as well as soluble sulfur present in the crude oil feedstock can degrade or destroy cracking catalyst employed during the refinement process thus inhibiting the production of quality products during the refinement process.

The method and process can be efficaciously employed to treat crude oil of having API gravity less than 50° API, less than 40° API, less than 30° API. In certain embodiments, the crude oil to be treated can have an API between 10° API and 50° API, between 10° API and 40°API, between 10° API and 30° API. In certain embodiments, the crude oil to be treated can have an API gravity between 30° API and 40° API which is typically classified as medium crude oil or less than 30° API, typically classified as heavy crude oil. Where desired or required, the process stream that is treated by the method and material disclosed herein can be a mixture of heavy crude oil and light crude oil present at a ratio between 10:1 and 1:4 heavy crude oil to light crude oil respectively; ratios between 8:1 and 1:4; ratios between 4:1 and 1:4; 10:1 and 1:3; 10:1 and 1:2; 10:1 and 1:1 are contemplated in certain embodiments.

The crude oil to be treated includes sulfur compounds typically present in a concentration greater than 1000 ppm. In certain crude oil process streams, the sulfur compounds can be present at a concentration greater than 5000 ppm; greater than 10,000 ppm; greater than 20,000 ppm; greater than 25,000 ppm; greater than 30,000 ppm greater than 35,000 ppm. It is contemplated that crude oil subject to treatment by the process as disclosed herein can have a sulfur concentration between 1000 ppm and 40,000 ppm; between 5000 ppm and 40,000 ppm; between 10,000 ppm and 40,000 ppm.

The sulfur material compounds present in the crude oil include, but are not limited to hydrogen sulfide, elemental sulfur, at least one-SH group-containing compound, and mixtures thereof. In the present disclosure, —SH group-containing compounds can have the general formula R—SH in which R can be an alkyl group, an aryl group, and aralkyl group. Non-limiting examples of alkyl groups include methyl, ethyl, propyl, isopropyl, n-butyl, isobutyl, sec-butyl, t-butyl and the like. Non-limiting examples of aryl groups include substituted and unsubstituted phenyl groups.

The present disclosure is also directed to a process for delivering and/or treating crude oil that can include dewatering and degassing crude oil present in a crude oil stream such as that derived from a well head in which the crude oil stream has a sulfur material content between 1000 ppm and 400,000 ppm in which the sulfur material content comprising hydrogen sulfide and elemental sulfur. After degassing and dewatering the crude oil stream, delivering the crude oil stream into a crude oil delivery conduit system, the crude oil delivery conduit system having an inlet and an outlet, at least one fluid mixing mechanism positioned in the crude oil delivery conduit system, and at least one crude oil treatment composition delivery inlet with the crude oil delivery inlet positioned between the inlet of the crude oil delivery system and the at least one fluid mixing mechanism. The process also includes the step of delivering a metered volume of a treatment composition through the at least one crude oil treatment composition inlet into contact with the crude oil stream transiting the crude oil delivery system.

In certain embodiments, there is disclosed a method of reducing sulfur material concentration such as sulfide in crude oil that comprises contacting crude oil having an elevated sulfur concentration with an effective amount of a treatment composition that is composed of at least one polar protic solvent and an anhydrous inorganic hydroxide material such that the treatment composition has a pH greater that 10; greater than 11; greater than 12. In certain embodiments, the at least one polar protic solvent and an anhydrous inorganic hydroxide material can be present at a ratio between 3:1 and 1:3 solvent to hydroxide compound respectively. In certain embodiments, the ratio of solvent to inorganic hydroxide material can be 1:1.

Also disclosed herein is a well field crude oil system that comprises at least one pipe having an upstream end and a downstream end and crude oil composition present in the pipe such that the crude oil composition proximate to the upstream end of the pipe is composed of crude oil having a hydrogen sulfide content greater than 1000 ppm, inorganic hydroxide and a polar aprotic solvent compound and the crude oil composition at the downstream end of the pipe is composed of crude oil having a sulfide concertation less than 1000 ppm and between 0.1 and 5% by volume of a polar aprotic solvent.

In the process described, crude oil having sulfur impurities such as that produced from a well head can be contacted by or dosed with a treatment composition that is introduced into contact with the crude oil process stream. The treatment composition employed is composed of at least one polar protic solvent material and a suitable strong base such as a hydroxide material present in effective ratios. In certain embodiments, the hydroxide material present in concentrations between 1 molar to 5 molar in the solvent to produce a solution pH greater than 12. Where desired or required, the hydroxide material can be an inorganic hydroxide material composed in whole or in part of one or more inorganic hydroxide compounds. Where desired or required, the inorganic hydroxide material can be anhydrous.

The polar protic solvent component can be an inorganic material, an organic material or a combination of inorganic materials and organic materials that exhibit sufficient solvation and/or miscibility with crude oil. Where desired or required, the polar protic solvent component can have a boiling point between 50° C. and 150° C. and a dielectric constant between 5 and 80, with a boiling point between 65° C. and 120° C. and a dielectric constant between 20 and 80 being employed in certain embodiments.

“Protic solvent” as this term is employed in this disclosure is construed as a solvent material that contains at least one labile H⁺ and the ability to dissolve salts therein. Where desired, the polar protic solvent component can be selected from the group consisting of water, C-2 to C-6 substituted and unsubstituted alcohols, C-2 to C-6 substituted and unsubstituted carboxylic acids and mixtures thereof.

The polar protic solvent component can include one or more of the following: methanol, ethanol, n-butanol, isopropanol, formic acid, acetic acid and water. It is contemplated that the protic solvent component can be selected from the group consisting of methanol, ethanol, n-butanol, isopropanol, formic acid, acetic acid, propanoic acid, water and mixtures thereof. In certain embodiments, the polar protic solvent can be a mixture of ethanol and methanol in any suitable ratio. In certain embodiments, the polar protic solvent can be methanol. In certain embodiments, the polar protic solvent can be ethanol.

It is also contemplated that the polar protic solvent component of the treatment material can include quantities of one or more non-protic solvent compounds where desired or required, provided that the resulting polar protic component maintains the physical characteristics as outlined.

The treatment composition for reducing sulfide concentration in crude oil material also includes an effective amount of an inorganic strong base dissolved and/or dispersed in the polar protic solvent component. The inorganic strong base component can be an inorganic hydroxide material can be composed of one or more suitable strong inorganic bases which can include Group I hydroxides, Group II hydroxides and mixtures thereof. In certain embodiments, the strong inorganic base can be selected from the group consisting of sodium hydroxide, potassium hydroxide, magnesium hydroxide, calcium hydroxide and mixtures thereof. In certain embodiments anhydrous granular sodium hydroxide is integrated into the polar protic solvent.

The inorganic strong base component can be present in the treatment composition in an amount sufficient to provide a composition pH greater than 10. In certain embodiments, the inorganic strong base component will be present in an amount sufficient to provide a pH greater than 12. In certain embodiments, the inorganic strong base component can be present in the protic polar solvent in an amount between 1 ml and 500 ml inorganic strong base per liter of protic polar solvent. In certain embodiments, it is contemplated that the ratio of inorganic strong base to solvent can be in the range of 3:1 to 1:3 base to solvent respectively.

Where desired or required, the treatment composition as disclosed herein can also include an effective amount of an inorganic sulfite compound. In certain embodiments, the sulfite compound can be selected from the group consisting of Group I sulfite compounds, Group II sulfite compounds and mixtures thereof. In certain embodiments, the sulfite compound can be selected from the group consisting of sodium sulfite, potassium sulfite, calcium sulfite and mixtures thereof. Where desired to required, the sulfite compound can be anhydrous and can produce a solution pH of at least 9 at 126 g/L.

In certain embodiments, the inorganic sulfite compound can be present in an effective amount in the treatment composition in certain embodiments. The inorganic sulfite compound can be present in an amount between 0.1 and 250 g/liter of protic polar solvent; between 0.5 and 250 g/liter of protic solvent; between 1 and 250 g/liter of polar protic solvent; between 2 and 250 g/liter of polar protic solvent; between 5 and 250 g/liter of polar protic solvent; between 10 and 250 g/liter of polar protic solvent; between 20 and 250 g/liter of polar protic solvent; between 50 and 250 g/liter of polar protic solvent; between 100 and 250 g/liter of polar protic solvent; between 200 and 250 g/liter of polar protic solvent; 0.1 and 150 g/liter of protic polar solvent; between 0.5 and 150 g/liter of protic solvent; between 1 and 150 g/liter of polar protic solvent; between 2 and 150 g/liter of polar protic solvent; between 5 and 150 g/liter of polar protic solvent; between 10 and 150 g/liter of polar protic solvent; between 20 and 150 g/liter of polar protic solvent; between 50 and 150 g/liter of polar protic solvent; between 100 and 150 g/liter of polar protic solvent; 0.1 and 100 g/liter of protic polar solvent; between 0.5 and 100 g/liter of protic solvent; between 1 and 100 g/liter of polar protic solvent; between 2 and 100 g/liter of polar protic solvent; between 5 and 100 g/liter of polar protic solvent; between 10 and 100 g/liter of polar protic solvent; between 20 and 100 g/liter of polar protic solvent; between 50 and 100 g/liter of polar protic solvent; between 75 and 100 g/liter of polar protic solvent.

Where desired or required, the treatment composition for reducing sulfite concentration in a crude oil material can comprise between 0.5 and 8.0% by volume of an inorganic strong base component such as disclosed herein in mixture with a polar protic solvent component that has a boiling point between 50° C. and 150° C., a dielectric constant between 5 and 80. As discussed, the inorganic strong base can be a hydroxide compound selected from the group consisting of Group I hydroxides, Group II hydroxides, and mixtures thereof and can be anhydrous. In certain embodiments the inorganic strong base can be sodium hydroxide. The protic polar solvent component can be selected from the group consisting of methanol, ethanol, propanol, isopropanol, acetic acid, propanoic acid and mixtures thereof, and mixtures thereof. In certain embodiments, the protic polar solvent can be methanol.

Where desired or required, the inorganic strong base component can be admixed with the polar protic solvent in a manner that produces between 0.5 and 8.0% by volume inorganic strong base material in the treatment composition at any time prior to administration. In certain embodiments, the resulting treatment composition can be adminstered as a ready mixed composition.

In certain embodiments, the inorganic strong base component can be present in the composition in an amount between 0.5 and 7.0 volume %; between 0.5 and 6.0 volume %; between 0.5 and 5.0 volume %; between 0.5 and 4.0 volume %; between 0.5 and 3.0 volume %; between 0.5 and 2.0 volume %; between 0.5 and 1.0 volume %; between 1.5 and 7.0 volume %; between 1.5 and 6.0 volume %; between 1.5 and 5.0 volume %; between 1.5 and 4.0 volume %; between 1.5 and 3.0 volume %; between 1.5 and 2.0 volume %; between 2.5 and 7.0 volume %; between 2.5 and 6.0 volume %; between 2.5 and 5.0 volume %; between 2.5 and 4.0 volume %; between 2.5 and 3.0 volume %; 3.5 and 7.0 volume %; between 3.5 and 6.0 volume %; between 3.5 and 5.0 volume %; between 3.5 and 4.0 volume %; 4.0 and 7.0 volume %; between 4.0 and 6.0 volume %; between 4.0 and 5.0 volume %; 3.5 and 6.5 volume %; between 3.5 and 5.5 volume %; between 3.5 and 4.5 volume %.

Where desired or required, the treatment composition disclosed and employed can include a selected from the group consisting of Group I sulfite compounds, Group II sulfite compounds, and mixtures thereof that is dissolved or dispersed in the polar protic solvent component can be present in an amount between 0.1 weight % and 5.0 weight %; between 0.5 and 5.0 weight %; between 1.0 and 5.0 weight %; between 1.5 and 5.0 weight %; between 2.0 and 5.0 weight %; between 3.0 and 5.0 weight %; between 4.0 and 5.0 weight %; between 0.1 weight % and 4.0 weight %; between 0.5 and 4.0 weight %; between 1.0 and 4.0 weight %; between 1.5 and 4.0 weight %; between 2.0 and 4.0 weight %; between 3.0 and 4.0 weight %.

The present disclosure also contemplates a process and method for reducing sulfur in petroleum materials such as crude oil. In the process 100 as set forth in FIG. 1, an effective amount of a treatment composition comprising an inorganic base component contained in a protic polar solvent as disclosed is introduced into contact with crude oil to comprise dosing or contacting step as at reference numeral 110. The treatment composition is permitted to admix with the crude oil process stream for an interval sufficient to convert sulfur compound material including but not limited to sulfides present in the crude oil to sulfate compounds as at reference numeral 120. Once a suitable quantity of sulfur compounds such as hydrogen sulfide has been converted to sulfate compounds, at least a portion of the sulfate compounds can be separated from the crude oil material as at refence numeral 130. The process 100 as disclosed also contemplates multiple dosing steps as desired or required.

The dosing or contacting step 110 can occur at any suitable location in the associated crude oil recovery or transport operations. In certain applications, the contacting step 110 can occur after one or more initial separation operation(s) in which water and/or gaseous material such as natural gas has been removed from the crude oil. While it is contemplated that the contacting step can be implemented using equipment of various configurations, the present disclosure provides an apparatus and configuration that can be employed in certain implementations of the process and method as disclosed by way of non-limiting example.

In the process set up 200 as depicted in FIG. 2, treatment composition such as the treatment composition disclosed herein can be delivered from a suitable treatment composition holding tank 210 via suitable treatment composition delivery tube(s) such as at least one composition delivery tube 212 and dosing pump(s) 214. In the process set up 200, the treatment composition delivery tubes exit into crude oil conveying tube 216 at a location immediately downstream of the crude oil separation device such as three-part separator 218. The sour crude to be process can be material that exits one or more well heads such as well head 208.

The material that exits the well head 208 can be a commingled crude oil stream that can include aqueous components and/or gaseous components in addition to the crude oil material. The aqueous components and/or gaseous components can be entrained or otherwise associated with the crude oil component to be further processed. In the embodiment depicted in FIG. 2, the separation device 218 includes suitable mechanisms and/or configurations to accomplish separation of all or a portion of the aqueous portion such as aqueous portion 218a and/or all or a portion of the gaseous portion 218b from the crude oil component 218c. In certain embodiments, the aqueous portion 218a can be removed via one or more devices such as drains(s) 219a contiguously connected to the main body of the separator 218 which can convey the separated aqueous portion 219a out of the separator 218 along with sulfur-containing material as sour water to suitable processing, treatment and/or disposal processes and locations. In certain embodiments, the gaseous portion 218b can be removed via one or more devices such as conduit(s) 219b contiguously connected to the main body of the separator 218 which can convey the separated gaseous portion 219b out of the separator 218 along with sulfur containing material as sour gas to suitable processing, treatment and/or disposal processes and locations.

In the embodiment as depicted in FIG. 2, the crude oil conveying tube 216 can be equipped with at least one static mixer 220 and at least one treatment composition delivery tube 212 can be positioned to exit into the crude oil conveying tube immediately upstream of the at least one static mixer 220. In the system depicted in FIG. 2, two static mixers 220 and treatment composition delivery tubes 212 are illustrated. It is contemplated that multiple iterations a configuration including at least one static mixer static and delivery tube can be employed as needed or desired.

Once the crude oil has been treated, the crude oil process stream having hydrogen sulfide and sulfur compounds suitably sequestered and/or mitigated can be directed through a suitable sale meter 222 and into the suitable pipeline transport system 224.

The method and process as disclosed herein can proceed at a wide range of ambient temperatures. It is believed that the process as disclosed herein can be employed effectively as ambient temperatures of 5° C. and above in many implementations. It is also understood that temperature at well head can reach temperatures of 100° C. to 130° C. in certain situations. It is theorized that elevated temperature ranges due to either latent heat contained in the crude oil process stream or imparted by external means can be utilized to facilitate or support the desired reaction mechanisms in certain instances.

Without being bound to any theory, it is believed that the sulfur-containing components such as sulfide components that are sequestered and/or mitigated are ones for which formation in the process as disclosed herein generates electron energy. It is believed that some or all of this electron energy can be harvested to provide electrical power that can be used in the well field or provided to the electrical grid.

In certain embodiments such as the system illustrated in FIG. 2, the treatment composition can be introduced directly into the crude oil process stream. The amount of treatment composition dosed or added to the crude oil process stream will be that amount sufficient to effectuate the desired result over a sustained period of time and may be as low as 0.5 ml per liter of crude oil feed stock. Dosing rates between 0.5 ml and 5 ml of treatment composition per liter of crude oil feed stock are contemplated. In certain embodiments, dosing rates of 1.0 ml per liter of crude oil feed stock, 1.5 ml per liter of crude oil feed stock; 2.0 ml per liter crude oil feed stock; 2.5 ml per liter of crude oil feed stock; 3.0 ml per liter of crude oil feed stock; 3.5 ml per liter of crude oil feed stock; 4.0 ml per liter of crude oil feed stock; 4.5 ml per liter of crude oil feed stock; 5.0 ml per liter of crude oil feed stock can be employed.

The process as disclosed herein contemplates direct dosing of the treatment composition into contact with the crude oil process stream to be treated. It is also with in the purview of this disclosure that the treatment composition can be mixed with one or more carrier materials prior to introduction into contact with the crude oil process stream to be treated. In certain embodiments, the treatment composition can be admixed with a portion of sweet crude oil prior to introduction into contact with a sour crude oil process stream to be treated.

An alternate treatment composition delivery set-up 300 is illustrated in FIG. 3 which provides a non-limiting example of the process of admixing the treatment composition with a carrier material such as sweet crude oil prior to introduction into the crude oil process stream to be treated.

In FIG. 3, a comingled crude oil process stream is delivered from a suitable well head 310 to a separation device such the three phase separator 312 as illustrated. In the embodiment illustrated in FIG. 3A, a comingled crude oil process stream such as that is produced at a well head such as well head 310 can be introduced into a suitable separation device such as three phase separator 312. The comingled crude oil process stream can include aqueous material, gaseous material or both in addition to the crude oil material. A suitable three phase separator can be configured and/or include mechanisms that facilitate separation of at least a portion of the aqueous phase and at least a portion of the gaseous phase from contact with the crude oil component. The amount of aqueous material and/or gaseous material that is separated will be that amount sufficient to provide a crude oil process stream with a suitably limited amount of water for ultimate end use applications. The amount of gaseous phase material that is separated from the comingled crude oil process stream can be that amount sufficient to produce a crude oil process stream with an amount or level of entrained gaseous material in the crude oil process stream that is suitable for subsequent processing or end use applications. The aqueous phase that is separated from sour crude can include elevated levels of target material such as sulfur-containing material and can be referred to as sour gas.

The separator such as three phase separator 312 facilitates the separation of the component(s) of the comingled crude oil process stream that is produced from well head 310. Such separators can be configured with suitable conduits or other means to facilitate removal and conveyance of the respective aqueous component or gaseous component from the crude oil process stream as well ca conveyance to suitable treatment and/or disposal locations. In system 300 depicted in FIG. 3, the separator 312 includes at least one sour water drain 317 and at least one gas vent pipe 319.

Once separation is complete, the dewatered, degassed sour crude feed stock can be conveyed into a suitable processing tank such as processing tank 314 via suitable conduits 316 and pumps such as feed pump 318. In certain embodiments, it is contemplated that the conduit 316 can be positioned to introduce the degassed sour crude oil feed stock or process into the processing tank in a manner that facilitates admixture with components contained in the processing tank 316 at a location proximate to the top region 314a. Other locations or positions for entrance of conduit 316 are also within the purview of this disclosure.

Processing tank 314 is configured to contain suitable volume of sweet crude and is equipped with a suitable circulation system 320 such as a circulation pump and conduit system as illustrated. Processing tank 314 can be configured to hold a predetermined volume of sweet crude oil 313 as well as a sweet crude oil head space 317.

Treatment composition can be delivered to the processing tank 314 from a suitable treatment composition holding tank 324 via suitable treatment composition delivery tube(s) 325 and dosing pump(s) 326. The treatment composition can be delivered into the processing tank 314 in a manner that facilitates admixture with the sour crude oil process stream. In the embodiment depicted in FIG. 3, the treatment composition is removed from the treatment composition holding tank 324 and is introduced at a location immediately upstream of the circulation pump 321 in the circulation system 320 that is associated with processing tank 314. The resulting mixture or a portion thereof can then be delivered to suitable downstream processing operations.

In the embodiment illustrated in FIG. 3, the crude oil process stream is introduced into the top of processing tank 314. It is contemplated that viscosity differences between the crude oil process stream material and the sweet crude material will result in a sweet crude head space through which the crude oil process stream material will settle through the sweet crude headspace material comingling with the sweet crude material. The portions of the resulting mixture can be drawn off and admixed with treatment composition material and reintroduced into the processing tank 314, It is contemplated that portions of the resulting material can be removed sequentially as desired or required.

Also disclosed is a system for processing and conveying crude oil from a well head that comprises a crude oil conveying apparatus including at least one conduit that has an upstream end and a downstream end. When in use, the system for processing and conveying crude oil includes a pipe or conduit having crude oil traveling therethrough. The crude oil that is traveling through the pipe has a sulfur material concentration at the upstream end greater than 0.05% by volume, 0.1% by volume, 0.5% by volume, 1.0% volume in certain embodiments. The crude oil process stream travelling through the pipe has a sulfur material concentration of less than 0.5% by volume and between 0.1 and 5% by volume of a polar aprotic solvent at the downstream end of the pipe or conduit. In certain embodiments, the crude oil present and passing through the second end of the pipe will have a sulfur material concentration of less than 0.1% by volume, less than 0.05% by volume.

The system can also include one or more devices configured to separate components such as gas and water from the crude oil stream such as three-part separators and the like. In the well field crude oil processing and conveying system as disclosed, the pipe present in the crude oil conveying apparatus is in fluid communication with at least one separation device located upstream of the pipe and at least one sales meter located downstream. In certain applications, it is believed that the treatment composition and/or apparatus as disclosed herein can be employed produce crude oil material having attributes at or approaching those required to be classified as sweet crude oil and thus can be priced accordingly.

The crude oil conveying apparatus can also include at least one fluid mixing device. In certain embodiments, the at least one fluid mixing device can be a static mixer integrated into the conduit. It is also contemplated that the mixing device can be configured as a circulating pump if desired or required.

In order to better understand the invention disclosed herein, the following examples are presented. The examples are to be considered illustrative and are not to be viewed as limiting the scope of the present disclosure or claimed subject matter

Example I

Several crude oil samples having APIs which vary between 6 and 50 are studied using the treatment composition as disclosed herein. The samples are each placed in a column and are dosed with a solution composed of 800 milliliters methanol 200 milliliters anhydrous sodium hydroxide at rates of 0.5 ml per liter; 1 ml per liter; 2.5 ml per liter; 4 ml per liter and 5 ml per liter. Each of these studies validates that each chemical components have a quantified reaction showing the blended elements plays a key role in the mitigation of sulfur containing materials such as H₂S. Based on dosing rate versus time versus depletion of hydrogen sulfide to zero.

The tests indicate that the treatment composition is miscible in crude oil materials including bunker fuel and asphaltenes as well as heavy and lite crude where organic acids are present.

The alcohol component of the treatment composition such as methanol blends with the heavy and lite crude exhibit a solution solubility which facilitates hydroxide migration through the crude process stream neutralizing the acidic particles suspended in the crude oil stream with process stream pH changing from acidic to neutral ranges of 7.0 to 7.5.

The sodium hydroxide component of the treatment composition reacts with soluble sulfur present in the crude oil sample thereby eliciting a phase change in the sulfur component liberating electrons and changing sulfur to sulphate.

Example II

In order to evaluate the performance of the composition and method disclosed, samples of heavy crude bunker fuel having an API up to 30 containing bunker fuel components as well as asphaltenes that have been processed in a three-part separator are analyzed for sulfur content and determined to have respective sulfur contents of 0.1%, 0.5%, 1.0%, 5.0% with the sulfur content component composed of hydrogen sulfate and dissolved sulfur. The samples placed in a column and are dosed with a solution composed of 945 milliliters methanol 40 milliliters sodium anhydrous hydroxide and 50 grams of sodium sulfite flakes at rates of 0.1 ml per liter; 0.5 ml per liter; 1 ml per liter; 2.5 ml per liter; 4 ml per liter and 5 ml per liter. The sodium hydroxide 50/50 wt % blended at a 1.1 molar solution has a PH of 13.35. spot tests on the material being analyzed indicated that the material was reacting with components of the crude oil sample.

The methanol carrier of the treatment composition solubilizes into the heavy crude material and migrates as a reactant through the column and is found to neutralize acidic particles present therein changing the PH from 6.2 to a neutral PH of 7 to 7.2.

The results appear to support the hypothesis that The NAOH 50/50 wt % blended at a 1.1 molar solution has a PH of 13.35 has the reactive energy to blend and neutralize the organic acids shifting the heavy crude acids to a neutral state. The NaOH reaction appears to result in the reduction of soluble sulfur to sulfite with the polar organic solvent methanol functioning as an elemental receptor for the discharged sulfur electron which then allows the sulfur to change to a sulfate phase.

Example III

In order to evaluate the performance of the composition and method disclosed, of light end crude including distillates cuts composed of naphtha, and short chain hydrocarbons are determined to have a sulfur content of 0.1%, 0.5%, 1.0% composed of hydrogen sulfate and dissolved sulfur. The respective samples are dosed at rates of 0.5 ml to 5 ml per with a composition as disclosed herein composed of 945 milliliters methanol, 40 milliliters sodium anhydrous hydroxide and 50 grams of sodium sulfite flakes at the defined dosing rates 0.5 ml per liter; 1 ml per liter; 2.5 ml per liter; 4 ml per liter and 5 ml per liter. It is observed that the methanol blend of the composition as employed solubilizes in the hydrogen sulfide laden light crude and functions as a diluent carrier. The sodium hydroxide is blended at a 1.1 molar ratio 40 ml per liter, having a pH of 12.95. With dosing, it is observed that the sulfur phase present in the light end crude is present as hydrogen sulfate as well as solubilized sulfur deprotonates.

Example IV

In order to investigate the interactions between polar solvents and sodium sulfite, 50 grams of sodium sulfite flakes are admixed with 100 ml of the polar solvents, methanol and water respectively. Maximum saturation is 5.1 gm of sodium sulfite in 100 gm of methanol.

Example V

Various crude oils, both heavy and light, are studied having API values from API 6 to API 50. The specific crude oil types are listed Table I. The various crude oil types are tested against the following compositions:

• • A. 900 milliliters methanol, 40 milliliters sodium anhydrous hydroxide at a 1.1 molar ratio, and 50 grams of sodium sulfite flakes;
  • B. 650 milliliters methanol, 40 milliliters sodium anhydrous hydroxide at a 1.1 molar ratio, and 50 grams of sodium sulfite flakes
  • C. 900 milliliters methanol, 20 milliliters sodium anhydrous hydroxide at a 1.1 molar ratio, and 25 grams of sodium sulfite flakes
  • D. 900 milliliters methanol 40 milliliters sodium anhydrous hydroxide at a 1.1 molar ratio;
  • E. 600 milliliters methanol 40 milliliters sodium anhydrous hydroxide at a 1.1 molar ratio;
    The treatment composition produced lower sulfur component concentration in the samples tested.

While the invention has been described in connection with certain embodiments, it is to be understood that the invention is not to be limited to the disclosed embodiments but, on the contrary, is intended to cover various modifications and equivalent arrangements included within the scope of the appended claims, which scope is to be accorded the broadest interpretation so as to encompass all such modifications and equivalent structures as is permitted under the law.