Method and device for treatment of liquid petroleum products having high concentrations of sulfur compounds

Abstract

Process, method and apparatus for reducing sulfide contaminants in a crude oil stream.

Description

Atty. Doc. No. BOHRK-102-B-WO (client reference)METHOD AND DEVICE FOR TREATMENT OF LIQUID PETROLEUM PRODUCTS HAVING HIGH CONCENTRATIONS OF SULFUR COMPOUNDSTECHNICAL FIELD roooii The present application claims the benefit of priority to United States Provisional Patent Application Serial Number 63 / 702,040 filed October 1, 2024, and United States Nonprovisional Application serial Number 19 / 343,579 filed September 29, 2025, the specifications of which is incorporated by reference in its entirety herein.

[0002] This disclosure relates to methods and devices for treatment of liquid petroleum products such as crude oil having high concentrations of sulfur compounds such as hydrogen sulfide and aromatic sulfur compounds.BACKGROUND

[0003] Sulfur compounds such as 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. Cude 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.

[0004] 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 ornear 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.

[0005] Various proposals have been presented to address and mitigate sulfur concentrations in crude oil. In processes that include introduction of treatment compositions, the sulfur reduction and mitigation process is complicated by various physical characteristics of the crude oil stream including but not limited to viscosity, miscibility and the like. It I is desirable to provide devices that can facilitate admixture and interaction between treatment compositions and petroleum product streams such as crude oil streams.SUMMARY

[0006] 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.

[0007] Also disclosed herein is a device for introducing a treatment composition into contact with a crude oils process stream that facilitates component admixture and exposure and reaction of sulfur compounds such as one of more of hydrogen sulfide, aromatic sulfur compounds and the like to reduce or mitigate sulfur content in the crude oil process stream.

[0008] 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 pail 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.

[0009] In certain embodiments, the device or apparatus employed to accomplish sulfur content reductio and / or remediation includes a crude oil conveying conduit having an oil inlet and an oil outlet distal to the oil inlet, at least one mixer associated with the crude oil conveyingconduit, and at least one treatment fluid holding tank in fluid communication with the erode oil conveying conduit. It is contemplated that one or more mixers can be static mixers. It is contemplated that one or more mixers can be a combination of crude oil recirculation devices and static mixers. It is contemplated that at least one mixing device can include a cyclonic mixing device that is in communication with the one treatment fluid holding tank and the erode oil conveying conduit.

[0010] 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.

[0011] In certain embodiments, the treatment composition will have an initial pH greater than 12.

[0012] 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.

[0013] 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.

[0014] 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 havingan aromatic sulfide compound content greater than 0.1 % by weight. Tn certain embodiments, the resulting product will be crude oil having a sulfide content between 0 and 1000 ppm.

[0015] 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 pipeline 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.

[0016] 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 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.

[0017] 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

[0018] 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.

[0019] FIG. 1 is process diagram of an embodiment of the crude oil treatment system as disclosed herein;

[0020] FIG.2 is a diagrammatic depiction of an embodiment of the process system as disclosed herein;

[0021] FIG. 3 is a diagrammatic depiction of the treatment system of Fig 1 in which sweet crude is admixed with the treatment composition;

[0022] FIG. 4a is a diagram of an embodiment of a cyclonic mixing device that can be employed in the treatment system of Figs 2 or 3;

[0023] FIG. 4b is a detail view of an embodiment of a venturi tube that can be employed in the cyclonic mixing device of Fig. 4a;

[0024] FIG. 5 is a top view of an embodiment of a horizontal capillary control device which can be employed in the systems depicted in Figs.l to 3;

[0025] FIG. 6 is a partial cut-away side view of the horizontal capillary control device of Fig. 5;

[0026] FIG. 7 is a side elevational view of an embodiment of a treatment fluid introduction housing as disclosed herein;

[0027] FIG. 8 is a side view of the fluid treatment introduction housing of Fig. 7 with an embodiment of the cyclonic mixer in place therein;

[0028] FIG. 9A is an upper view of an embodiment of a diffuser equipped with capillary bubble control as disclosed herein;

[0029] FIG. 9B is an lower view of the diffuser equipped with capillary bubble control of Fig. 9A; and

[0030] FIG. 10 an embodiment of a tower diffuser assembly employing bubble diffuser of Figs 9A and B in position.DETAILED DESCRIPTION

[0031] 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 singlecomponent 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.

[0032] 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.

[0033] 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.

[0034] 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.

[0035] 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.

[0036] 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.

[0037] 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.

[0038] The sulfur 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.

[0039] 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 oildelivery 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.

[0040] 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.

[0041] In the process as 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 pail of one or more inorganic hydroxide compounds. Where desired or required, the inorganic hydroxide material can be anhydrous.

[0042] 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.

[0043] 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. Wheredesired, 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.

[0044] 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.

[0045] 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.

[0046] 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.

[0047] 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.

[0048] Where desired or required, the treatment composition as disclosed herein can also include an effective amount of an inorganic sulfite compound. In certain embodiments, thesulfite 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 126g / L.

[0049] In certain embodiments, the inorganic sulfite compound can be present in an effective amount in the treatment composition in certain embodiments, the sulfite compound can present in an amount between 1 and 250 g per liter of protic polar solvent. 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.

[0050] 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.

[0051] 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 certaine embodiments, the resulting treatment composition can be adminstered as a ready mixed composition.

[0052] 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 %.

[0053] 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 %.

[0054] 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 as at reference numeral 110. The treatment composition is permitted to admix with the crude oil process stream for aninterval sufficient to convert sulfur compounds present in the crude oil to sulfate 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.

[0055] 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.

[0056] In the process set up 200 as depicted in Fig, 2, treatment composition 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 conduit 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.

[0057] It is contemplated that the process set up can be positioned at any suitable location. In certain implementations, process set up 200 can be positioned at a location downstream of crude oil separation devices such as three-part separator 218. It is understood that three-part separators and the like can be deployed at or near well head operations. It is contemplated that the process and method as disclosed can be implemented at or near well heads or other suitable crude oil processing facilities as desired or required.

[0058] It is also contemplated that multiple process set up 200 can be employed as desired or required. In certain applications multiple set ups 200 can be deployed either in series, in parallel or both to process the desired volume of crude oil at a suitable rate and effectiveness.

[0059] In the embodiment as depicted in Fig. 2, the crude conveying conduit 216 can be equipped with suitable means to facilitate intimate contact between one or more components of the treatment composition and the target compounds in the crude oil process stream. One non-limiting example of such devices are various instream mixing devices. In the embodiment depicted in Fig. 2, mixers such as static mixers can be employed to facilitate contact between components of the treatment composition and target compounds in the crude oil process stream which can include but are not necessarily limited to the sulfur-containing components. Other devices that will facilitate intimate contact between one or more components of the treatment composition and target compounds present in the crude oil processing stream are also considered with in the purview of this disclosure. Examples of which are outlined in this disclosure.

[0060] In the embodiment illustrated in Fig. 2 at least one treatment composition delivery tube 212 can be positioned to be introduce one or more suitable treatment compositions into the crude oil conveying tube immediately upstream of the associated 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 static mixers and delivery tubes can be employed as needed or desired.

[0061] Without being bound to any theory, it is believed that the various mixing devices as disclosed herein can impart mechanical energy to the admixture of crude oil process stream and treatment composition. Without being bound to any theory, it is believed that in addition to facilitating intimate contact between the components of the treatment composition and target compounds in the crude oil process stream, in certain applications and instances, the imparted mechanical energy can promote and advance the treatment reactions that occur between the one of more of the target compounds in the crude oil process stream and one or more of the components of the treatment composition.

[0062] 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.

[0063] In processes and systems as disclosed herein it is contemplated that, once the crude oil process stream has been treated, the crude oil process stream material has target compounds such as hydrogen sulfide and sulfur compounds suitably sequestered and / or mitigated and can bedirected to various downstream operations such as passage through suitable sale meters such as sales meter 222 and the suitable crude oil conveyance systems as is represented by pipeline system 224 and the like. In certain applications, it is believed that the treatment process and apparatus as disclosed herein can produce crude oil material having attributes at or approaching those required to be classified as sweet crude oil and thus can be priced accordingly.

[0064] Without being bound to any theory, it is believed that the process and compositions as disclosed herein either alone or in combination with the apparatus as disclosed, in addition to accomplishing desired reduction of target chemical contaminants such as sulfur containing compounds may also generates a measurable quantity of electron energy. It is believed that some or all of this electron energy is available for collection and harvest to provide electrical power that can be used in the field or provided to the electrical grid in general.

[0065] In certain implementations, the treatment composition can be 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.

[0066] Crude oil process streams vary in viscosity depending on factors such as well field location and the like. Certain embodiments such as the system illustrated in Fig. 2, contemplate usage with crude oil process streams having viscosities which will permit direct introduction of the treatment composition material into the crude oil process stream. In situations where the crude oil is more difficult to process, the present disclosure contemplates upstream or pretreatment modification of the crude oil process stream to facilitate treatment as disclosed herein.

[0067] It is also contemplated that the process and system as disclosed herein can be adapted to effectively treat and deliver crude oil. Thus, it is considered within the purview of this disclosure to perform a process for delivering crude oil that includes a step of degassing anddewatering crude oil present as a crude oil process stream such as that which can emanate from a well head. The crude oil stream that is processed can have a sulfur containing material content between 100 ppm and 400,000 ppm: between 1000 ppm and 400,000 ppm between 5000 ppm and 400,000 ppm. The sulfur containing material content can comprise hydrogen sulfide, elemental sulfur, mixtures of hydrogen sulfide and elemental sulfur.

[0068] After the crude oil stream is dewatered and degassed, the crude oil stream is delivered into a crude oil delivery conduit system, that has a crude oil conduit delivery system inlet and a crude oil conduit delivery system 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. Where desired or required, the crude oil conduit delivery inlet can be positioned between the inlet of the crude oil delivery conduit 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 crude oil treatment composition inlet into contact with the crude oil stream transiting the crude oil delivery system. The crude oil that transits the crude oil delivery system upstream of the mixing mechanism comprises crude oil, an inorganic strong base component, at least one polar aprotic solvent and between 100 ppm and 400,000 ppm sulfide content, between 500 ppm and 400,000 ppm sulfide content, between 1000 ppm and 400,000 ppm sulfide content. The crude oil transiting the crude oil delivery system at a location downstream of the mixing mechanism comprises crude oil, at least one inorganic sulfate and less than 100 ppm sulfide content less than 500 ppm sulfide content; less than 1000 ppm sulfide content.

[0069] 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 conduit 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.

[0070] 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 assocaited with the crude oil component to be further processed. In the embodiment depicted inFig. 2, the separation device or separator 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 218b 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 In the embodiment as depicted in Fig. 2, the crude oil conveying conduit 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.

[0071] 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.

[0072] An alternate treatment composition delivery system 300 is illustrated 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. 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 aqueousphase 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.

[0073] 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.

[0074] Once separation is complete the de watered, degassed sour crude feed stock can be conveyed into a suitable processing tank 314 via suitable conduits 316 and pumps 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 314 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.

[0075] Processing tank 314 is configured to contain a suitable volume of sweet crude oil and can be equipped with suitable circulation system 320 such as a circulation pumps and conduit system 320 as illustrated to support and facilitate mixture between sweet crude and suitable dosage amounts of the treatment composition.

[0076] Treatment composition can be delivered to the processing tank 314 from a suitable treatment composition holding tank 322 via suitable treatment composition delivery tube(s) 324 and can be metered by suitable means such as dosing pump(s) 326. In the embodiment depicted in Fig. 3, the treatment composition is introduced at a location immediately upstream of the circulation pump in the conduit system 320 associated with processing tank 314. The resulting mixture can then be delivered to suitable downstream processing operations.

[0077] 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 resultingmixture 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.

[0078] 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.

[0079]

[0080] 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.

[0081] 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.

[0082] Also disclosed is a device and system that can be integrated into crude oil delivery systems to introduce treatment compositions such as ones described herein in a manner that achieves efficient and effective mitigation of one or more target compounds such as sulfur- containing compounds present in the crude oil process stream. As broadly described that crudeoil treatment device includes a crude oil conveying conduit that has an oil inlet and an oil outlet distal to the oil inlet and at least one mixer device that is associated with the crude oil conveying conduit as well as at least one treatment fluid holding tank in fluid communication with the crude oil conveying conduit as depicted in Figs. 2 and 3.

[0083] Where desired or required, the mixer can be a suitable static mixer as illustrated in Fig. 2 or can be a recirculation system as depicted in Fig 3. It is also within the purview of this disclosure that the system can include features of both systems.

[0084] In certain implementations, it is contemplated that a treatment apparatus as disclosed herein can include one or more devices that can enhance contact between the treatment composition and the crude oil process stream to be treated. In some embodiments, the treatment apparatus can include at least one cyclonic mixer in fluid communication with some or all of the crude oil process stream to be treated. It is also contemplated that multiple cyclonic mixers can be positioned in series, in parallel or a combination both to introduce turbulence into the crude oil process stream and / or to facilitate contact between the material in the crude oil process stream and treatment composition materials. In certain embodiments, the at least one cyclonic mixing device can be in fluid communication with a suitable fluid treatment holding tank and with the crude oil process stream conveying conduit. In certain embodiments, a cyclonic mixer such as such as cyclonic mixing device 410 can be employed and can be in fluid communication with the at least one treatment fluid holding tank (not shown) and the crude oil conveying conduit (not shown).

[0085] In the embodiment as disclosed in Figs 4a and 4b, the cyclonic mixing device 410 can include a treatment fluid introduction chamber 412 that can have a geometric configuration suitable to support fluid flow therein, In the embodiment depicted, treatment fluid introduction chamber 412 has a generally cylindrical configuration. The treatment fluid introduction chamber 412 can have a treatment fluid introduction chamber diameter D and a treatment fluid introduction chamber height h. Where desired or required, the treatment fluid introduction chamber can be cylindrical. The treatment fluid introduction chamber 412 can have at least one treatment composition fluid introduction port 414.1n the embodiment depicted, the at least one treatment composition fluid introduction port 414 that can be located proximate to a first lateral face 416 connected to the side wall 417 of the treatment fluid introduction chamber 412 to define an initial chamber 419 in fluid communication with the introduction port 414 and orientedaxially thereto. Tn certain implementations, the treatment composition fluid introduction port 414 can be positioned and oriented to produce axial or vortex like travel in the chamber defined in the treatment fluid introduction chamber 412 as the treatment composition is introduced therein.

[0086] The treatment fluid introduction chamber 412 can also include a crude oil introduction port defined at a location in the treatment fluid introduction chamber 412 suitable to initiate mixture between the crude oil material to be treated and the treatment composition being introduced. In certain embodiments, the respective streams can be introduced at angles to one another.

[0087] In the embodiment illustrated, the cylindrical crude oil introduction port 418 is defined in first lateral face 416 of the treatment fluid introduction chamber 412. The cylindrical crude oil introduction port 418 can communicate with a suitable crude oil introduction pipe 420 can be placed in fluid communication with the crude oil process stream.

[0088] In certain embodiments, the crude oil introduction pipe 420 can project through the cylindrical crude oil introduction port 418 to a spaced distance into the treatment fluid introduction chamber 412. In certain embodiments, the outlet of the crude oil introduction pipe 420 can extend into the chamber to a distance that is sufficient to facilitate interaction with the axially traveling treatment composition stream introduced into the treatment fluid introduction chamber 412 through treatment composition fluid introduction port 414. In certain implementations, the introduced crude oil stream can be drawn into the vortex produced in by the circulating treatment composition material stream. Without being bound to any theory, it is believed that the shear’ forced produced in this interaction can enhance the chemical reaction that is initiated between the components of the process treatment stream and the target compounds present in the crude oil process stream.

[0089] In certain embodiments, the treatment composition fluid introduction port 414 can have dimensions that include height a and a dimensional width b and can be associated with an introduction sleeve 415 of similar dimensions. Where desired or required, the cylindrical crude oil introduction port 418 can be positioned on the first lateral face 416 such that the spaced distance between cylindrical crude oil introduction port 418 and outer edge of the lateral face has a value equal to a, with tolerances of +1%±± 5%, +10% being contemplated in certain embodiments. Where desired or required, the crude oil introduction pipe 420 can extend into thechamber defined in the cylindrical treatment fluid introduction chamber 412 a distance equal to b with tolerances of + 1%. + 5%. + 10% being contemplated in certain embodiments.

[0090] Where desired or required, the cylindrical crude oil introduction port 418 and associated crude oil introduction pipe 420 can have an average inner diameter value Dx with average inner diameter value Dx having a value that is between 20% and 80% of the value of treatment fluid introduction chamber diameter D. In certain embodiments the value of average inner diameter value Dx can between 30% and 80%, between 40% and 80%, between 50% and 80%, between 60% and 80%, between 70% and 80%, between 20% and 30%, between 30% and 40%, between 50% and 60%, between 60% and 70% between 70% and 80%.

[0091] The cyclonic mixing device 410 includes an intermediate transit region 422 contiguously connected to the cylindrical treatment fluid introduction chamber 412 at a location distal to the cylindrical crude oil introduction port 418. The dimensions of intermediate transit region 422 can be those that facilitate movement and mixing of the respective components. Without being bound to any theory, it is believed that the vortex motion initiated in the cylindrical treatment fluid introduction chamber 412 is concentrated and intensified in the intermediate transit region 422.

[0092] Where desired or required, the intermediate transit region 422 can be defined by an outer wall 424 that tapers from an upstream diameter DB having a value equal to the value of treatment fluid introduction chamber diameter D to an intermediate transit region outlet 426 having an inner diameter less than DB. In the embodiment depicted in Fig. 4a, the intermediate transit region as at intermediate transit region outlet 426 having a downstream diameter DBC having a value equal to Dx.

[0093] The cyclonic mixing device 410 as depicted in Fig 4a also include a connection pipe 428 contiguously connected to the intermediate transit region 422 at a location distal to the cylindrical treatment fluid introduction chamber 412. The connection pipe 428 can include at least one connection pipe inlet 431 and at least one connection pipe outlet 433. In the embodiment depicted in Fig 4a, the connection pipe inlet 431 is defined in first connection pipe face and can be connected to an intermediate transit region outlet 426 by any suitable manner.

[0094] Connection pipe 428 can have a suitable inner diameters Dp. In certain embodiments it is contemplated that the value Dp will be equal to the inner diameter value D of cylindricaltreatment fluid introduction chamber 412. Where desired or required, connection pipe 428 can have a height Hp that is equal to the value Dp.

[0095] Cyclonic mixing device 410 can have a dimensional transit height sufficient to produce intimate contact between the crude oil process stream and the components of the treatment composition. In certain embodiments, the treatment fluid introduction chamber 412 and the intermediate transit region 422 have a combined height value Hr. The cylindrical treatment fluid introduction chamber has a height h which is between 10 and 40% of Hr. The connection pipe 428 can have a height equal to or greater than connection pipe diameter and can define an interior chamber.

[0096] In the embodiment illustrated in the various drawing figures, intermediate transit region 422 can terminate in a venturi tube 430 at intermediate transit region outlet 426. It is contemplated a suitable outlet such as venturi tube 430. Venturi tube 430 can have any suitable dimensional configuration that will facilitate intimate contact between the crude oil process stream and the components of the treatment composition. In certain embodiments and applications, the venturi tube 430 can be configured as depicted in Fig. 4b.

[0097] The embodiment of venturi tube 430 as depicted in Fig. 4b, includes a convergent cone 432 located proximate to the intermediate transit region outlet 426 of the intermediate transit region 422 of cyclonic mixing device 410. The convergent cone 432 can have a convergent cone maximum diameter DX1 and can terminate in a convergent cone minimum diameter t. Where desired or required, convergent cone maximum diameter DX1 can have a value equal to the downstream diameter DBC of the intermediate transit region outlet 426.

[0098] In certain embodiments, the convergent cone 432 of venturi tube 430 can have a slope sufficient to further compress the liquid cyclonic action initiated in the prior regions. In certain embodiments the slope can be between 1 in 4 and 1 in 5 to achieve the convergent cone minimum diameter t. In the embodiment as illustrated, the convergent cone 432 can have a length Lvi and a convergent cone minimum diameter that is between 10% and 50% less than the convergent cone maximum diameter.

[0099] Venturi tube 430 as depicted in Fig. 4b also has a throat 434 in fluid communication with a downstream section of the convergent cone 432 and a divergent cone 436 in fluid communication with the throat 434 positioned distal to the convergent cone 432. In certain embodiments, throat 434 will have a length a length less than length Lvi. It is contemplated that,in certain embodiments, throat 434 can have a length that is less than 105 of the value of Lv2. in the embodiment illustrated in Fig 4b, throat 434 is an oblique junction between the wall so convergent cone 432 and divergent cone 436. Without being bound to any theory, it is believed that the passage through the venturi tube with the throat of the device as disclosed herein may initiate shear forces on the molecular' level that render certain target compounds more amenable to reaction and neutralization.

[0100] It is theorized that the configuration of the divergent cone 436, possibly in combination with the configuration of the connection pipe 428 may produce a unique cavitation event which can further accomplish the removal of compounds present in the crude oil process stream, among these are electron scavengers such as ammonia compounds which could serve to dampen or repress interaction between the process treatment composition and the target sulfur compounds present in the crude oil stream.

[0101] The crude oil treatment device 500 may also include various mechanisms and devices which can promote intimate contact between the crude oil process stream and the components of the treatment composition and / or maintain or enhance kinetic and mechanical forces induced on the reacting process material. These can include one or more bubblers that can introduce gaseous bubbles and associated turbulent flow to the treatment composition stream, the process stream or mixtures of both.

[0102] One embodiment of a bubbler that can be employed in the crude oil treatment device as disclosed herein is illustrated in Figs 5 and 6. Horizontal capillary controller 510 includes a hemispheric body 512 having a planar face 514. In certain embodiments, the horizontal capillary controller 510 can be located downstream of cyclonic mixing device(s) such as cyclonic mixing device 410. The planar face 514 can have a plurality of orifices 516 disposed radially on the planar face 514 of the hemispheric body 512 and can communicate with at least one channel defined therein. The horizontal capillary controller 510 also includes at least one inlet orifice 518 defined in the hemispheric body 512 at a location distal to the planar face in fluid contact with the process stream passing therethrough.

[0103] Where desired or required, the horizontal capillary controller 510 can be deployed in the treatment device and can be employed to introduce suitable gaseous material to the reacting process stream. The gaseous material can be an inert gas or mixture of inert gasses. It is alsowithin the purview of this disclosure that the gaseous material can be one that can include one or more components having interactive characteristics.

[0104] Where desired or required, the cyclonic mixing device 410 can be configured to incorporate one or more inline bubbler devices such as a diffuser assembly, an embodiment of which is illustrated in Figs. 9A, 9B and 10. One embodiment of suitable bubble diffusers 610 that can be employed is depicted in Figs. 9A and 9B. The bubble diffuser 610 includes a central conduit 612 defining a central fluid channel. The central conduit 612 can be configured with cylindrical wall 614, a planar face 616 connected to the cylindrical wall 614 and an opening 618 opposed to the planar face 616. A plurality of individual bubbler members 620 project angularly outward from the cylindrical wall 614 and are positioned radially around the cylindrical wall 614 each defining a channel communicating with the central conduit 612.

[0105] Each individual bubbler member 620 can be a cylindrical conduit that includes a plurality of tubular orifices that facilitates development of bubbles when a gaseous material is introduced into the central conduit 612. The orifices in the various individual bubbler members 620 can be the same or can vary from member to member to provide bubbles of differing sizes. The individual bubbler members 620 can project outward from the central conduit 612 at an angle suitable to direct the bubbles produced into the process stream in the manner desired. The individual bubbler members 620 can be positioned at the same angle relative to the central conduit for can be positioned at different angles as desired or required.

[0106] Nonlimiting examples of suitable gaseous materials include non-reactive gasses introduced for turbulence value as well various gasses that can support or assist the reactive process that renders sulfur compounds into a treatable or isolatable state, non-limiting examples of the latter include atmospheric air as well as oxygen, carbon dioxide and the like.

[0107] In the embodiment depicted in Figs. 9A and 9B, individual bubbler members 620 are axially oriented around the periphery of the central conduit 612. In the device as depicted seven members are positioned around the central conduit. Other numbers are also considered within the purview of this disclosure. In certain embodiments, the bubblers can project outward from the central conduit or channel in spaced axial relationship thereto.

[0108] The bubble diffuser 610 can be integrated into a suitable diffuser stack, a nonlimiting example of an embodiment of diffuser stack 650 is presented in Fig. 10. Bubble diffuser 610 is operatively connected to a suitable gas source such as central conduit 652 which can traversevarious flange members 654, 656 in fluid communication with a suitable pressurized gas source or a mechanism for generating pressurized gas in situ (not shown). The individual bubbler members 620 can be oriented relative to the fluid flow to provide the desired degree of fluid turbulence. In certain embodiments as illustrated, this orientation can be in a direction opposed to fluid flow however other orientations are considered to be with in the purview of this disclosure.

[0109] In the embodiment depicted in Fig. 10, the desired fluid can progress in a direction away from the flange members 654, 656. The gaseous bubbles produced by the bubble diffuser 610 and the associated fluid are directed upward past plate 653 and through separator screen 662 where the fluid and gaseous bubbles generated can pass though cylindrical capillary device 660 to induce further division in the bubbles produced. The material thus agitated can be introduced into subsequent process contact.

[0110] In certain embodiments, it is contemplated that elements such as separator screen 662 and cylindrical capillary device 660 will be dimensioned to fit operatively into a suitable housing (not shown).

[0111] One or more of the aforementioned devices can be housed in a suitable crude oil treatment device assembly which can be integrated into a crude oil process stream delivery conduit system at a suitable location, typically downstream of water and / or gaseous separators and upstream of any price metering devices. One embodiment of a crude oil treatment device 710 is depicted in Fig. 7.

[0112] Where desired or required, the crude oil delivery device 710 can include a treatment composition introduction conduit 712 connected to a fluid treatment composition mixing housing 714. The fluid treatment composition mixing housing 714 communicates with a T region 718. At least one crude oil process stream inlet 720 also communicates at T region 718 which communicates with a processing chamber region 722. The treatment composition mixing housing 716 also has at least one outlet for the resulting mixture of crude oil and treatment composition.

[0113] At least one mixing apparatus contained in the treatment composition mixing housing 716 and is oriented coaxial with its cylindrical walls. In certain embodiments, the treatment composition mixing apparatus can be a cyclonic mixing device such as cyclonic mixing device 410 as previously discussed. In certain embodiments, the cyclonic mixing device include a venturi tube such as was previously discussed. It is also contemplated that one or more venturitubes can be positioned in treatment composition mixing housing 716 independent of cyclone mixer as illustrated in Fig. 8.

[0114] 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 matterEXAMPLE I

[0115] 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.

[0116] 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.

[0117] 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.

[0118] 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

[0119] 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 sulfurcontent 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.

[0120] 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.

[0121] 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

[0122] In order to evaluate the performance of the composition and method disclosed, of light end crude including distillates cuts composed of naptha, 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

[0123] 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

[0124] 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 flakesC. 900 milliliters methanol, 20 milliliters sodium anhydrous hydroxide at a 1.1 molar ratio, and 25 grams of sodium sulfite flakesD. 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.TABLE I

[0125] 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.

Claims

AMENDED CLAIMS received by the International Bureau on 06 April 2026 (06.04.2026)What is claimed is:

1. A crude oil treatment device comprising: a crude oil conveying conduit having a crude oil inlet and a crude oil outlet distal to the crude oil inlet, the crude oil conveying conduit having a crude oil process stream conveyed therethrough; at least one mixer associated with the crude oil conveying conduit; and at least one treatment composition holding tank in fluid communication with the crude oil conveying conduit.

2. The crude oil treatment device of claim 1 , wherein the at least one mixer is a static mixer.

3. The crude oil treatment device of claim 1, wherein the at least one mixer is a crude oil recirculation device.

4. The crude oil treatment device of claim 1 , , wherein the at least one mixer includes at least one static mixer and at least one crude oil recirculation device.

5. The crude oil treatment device of claim 1, 2 or 3 wherein the at least one treatment composition holding tank is in communication with the crude oil conveying conduit via at least one cyclonic mixing device.

6. The crude oil treatment device of claim 5 wherein the cyclonic mixing device comprises: a cylindrical treatment fluid introduction chamber having a treatment fluid introduction chamber diameter D and a treatment fluid introduction chamber height h, the cylindrical treatment fluid introduction chamber having at least one axial treatment fluid introduction port and at least one cylindrical crude oil introduction port, the cylindrical crude oil introduction port located coaxial to the cylindrical treatment fluid introduction chamber and having an average inner diameter Dx, wherein Dx has a value that is37between 20% and 80% of the diameter of the cylindrical treatment fluid introduction chamber; an intermediate transit region contiguously connected to the cylindrical treatment fluid introduction chamber at a location distal to the cylindrical crude oil introduction port, the intermediate transit region having an outer wall that tapers from an upstream diameter DB having a value equal to D to an intermediate transit region outlet, the intermediate transit region outlet having a downstream diameter DBC having a value equal to Dx; and a connection pipe contiguously connected to the intermediate transit region at a location distal to the cylindrical treatment fluid introduction chamber, the connection pipe having a connection pipe inlet and a connection pipe outlet.

7. The crude oil treatment device of claim 6 further comprising a venturi tube in fluid communication with the intermediate transit region outlet and projecting in a chamber defined by the connection pipe.

8. The crude oil treatment device of claim 7 wherein the venturi tube comprises: a convergent cone located proximate to the outlet of the intermediate transit region of the cyclonic mixing device, the convergent cone having a convergent cone maximum diameter DX1 equal to a downstream diameter DBC of the intermediate transit region outlet, having a slope between 1 in 4 and 1 in 5, the convergent cone having a length Lvi and a convergent cone minimum diameter that is between 10% and 50% less than the convergent cone maximum diameter; a throat in fluid communication with a downstream section of the convergent cone; and a divergent cone in fluid communication with the throat distal to the convergent cone, the divergent cone having a slope between 1 in 4 and 1 in 5 and a length Lv2 that is less than length Lvi..

389. The crude oil treatment device of claim 8, wherein the throat of the venturi tube has a length less than length Lv2.

10. The crude oil treatment device of claim 9, wherein the cylindrical treatment fluid introduction chamber and the intermediate transit region have a combined height value HT, and the cylindrical treatment fluid introduction chamber has a height h which is between 10 and 40% of HT, and wherein the connection pipe has a height equal to or greater than connection pipe diameter.

11. The crude oil treatment device of claim 1 further comprising at least one horizontal capillary controller downstream of and in fluid contact with the at least one mixer.

12. The crude oil treatment device of claim 11 wherein the at least one horizontal capillary controller comprises a hemispheric body having a planar face oriented downstream relative to the mixer and a plurality of orifices defined in the planar face of the hemispheric body, the orifices disposed radially on the planar face of the hemispheric body and communicating with at least one channel defined therein and at least one inlet orifice positioned distal to the planar face of the hemispheric body in fluid contact with the crude oil process stream.

13. The crude oil treatment device of claim 1 further comprising a diffuser in fluid contact with one at least one of the treatment composition and the crude oil process stream, the diffuser comprising a central channel and a plurality of bubblers projecting from the central channel, the plurality of bubblers projecting outward from the central channel in spaced axial relationship thereto.

14. A crude oil treatment device component comprising: a treatment composition introduction conduit; a treatment composition mixing housing defining chamber in fluid communication with the treatment composition introduction conduit, the treatment composition mixing housing having at least one crude oil inlet and at least one process stream outlet; andat least one mixing apparatus contained in the treatment composition mixing housing coaxial to the treatment composition mixing housing, wherein the at least one mixing apparatus includes a cyclonic mixing device, the cyclonic mixing device including: a cylindrical treatment fluid introduction chamber having a treatment fluid introduction chamber diameter D and cylindrical treatment fluid introduction chamber height h, the cylindrical treatment fluid introduction chamber having at least one axial treatment fluid introduction port and at least one cylindrical crude oil introduction port, the cylindrical crude oil introduction port located coaxial to the cylindrical treatment fluid introduction chamber and having an average diameter Dx, wherein Dx has a value that is between 20% and 80% of the diameter of the cylindrical treatment fluid introduction chamber; an intermediate transit region contiguously connected to the cylindrical treatment fluid introduction chamber at a location distal to the cylindrical crude oil introduction port, the intermediate transit region having an outer wall that tapers from an upstream diameter DB having a value equal to D to an intermediate transit region outlet, the intermediate transit region outlet having a downstream diameter DBC having a value equal to Dx; and a connection pipe contiguously connected to the intermediate transit region at a location distal to the cylindrical treatment fluid introduction chamber, the connection pipe having a connection pipe outlet having a connection pipe outlet.

15. The crude oil treatment device component of claim 14 further comprising a venturi tube in fluid communication with the intermediate transit region outlet and projecting in an interior chamber defined by the connection pipe.

16. The crude oil treatment device component of claim 15 wherein the venturi tube comprises: a convergent cone located proximate to the outlet of the intermediate transit region of the cyclonic mixing device, the convergent cone having a convergent cone maximum diameter equal to the downstream diameter DBC of the intermediate transit region outlet, having a slope between1 in 4 and 1 in 5, the convergent cone having a length Lvi and a convergent cone minimum diameter that is between 10% and 50% less than the convergent cone maximum diameter; a throat in fluid communication with a downstream section of the convergent cone; and a divergent cone in fluid communication with the throat distal to the convergent cone, the divergent cone having a slope between 1 in 4 and 1 in 5 and a length Lv2 that is less than Lvi..

17. A process for delivering crude oil, the process comprising steps as follows: dewatering and degassing crude oil present in a crude oil stream emanating from a well head, the crude oil stream having a sulfur containing material content between 100 ppm and 400,000 ppm, the sulfur content comprising hydrogen sulfide and elemental sulfur; after the 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 a crude oil conduit delivery system inlet and a crude oil conduit delivery system 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 , the crude oil conduit delivery inlet positioned between the inlet of the crude oil delivery conduit system and the at least one fluid mixing mechanism; and delivering a metered volume of a treatment composition through the crude oil treatment composition inlet into contact with the crude oil stream transiting the crude oil delivery system; wherein the crude oil transiting the crude oil delivery system upstream of the mixing mechanism comprises crude oil, between 1000 and 400,000 ppm sulfide content, an inorganic strong base component and at least one polar aprotic solvent, and wherein the crude oil transiting the crude oil delivery system at a location downstream of the mixing mechanism comprises crude oil, less than 1000 ppm sulfide content and at least one inorganic sulfate.

18. The process of claim 17 further comprising the step of delivering crude oil having a sulfide content less than 1000 ppm to a sales volume metering device.

19. The process of claim 17, wherein the treatment composition comprises: between 0.5 and 8.0 % by volume of an inorganic strong base component, wherein the inorganic strong base component is a hydroxide compound selected from the group consisting of Group I hydroxides, Group II hydroxides, and mixtures thereof; between 0 and 5.0 % by weight of a sulfite compound selected from the group consisting of Group I sulfite compounds, Group II sulfite compounds, and mixtures thereof; and a polar protic solvent component having a boiling point between 50 °C and 150 °C, a dielectric constant between 5 and 80.

20. A treatment composition for reducing sulfur concentration in a crude oil material having a sulfide content greater than 1000 ppm, the treatment composition comprising: between 0.5 and 8.0 % by volume of an inorganic strong base component, wherein the inorganic strong base component is a hydroxide compound selected from the group consisting of Group I hydroxides, Group II hydroxides, and mixtures thereof; between 0 and 5.0 % by weight of a sulfite compound selected from the group consisting of Group I sulfite compounds, Group II sulfite compounds, and mixtures thereof; and a polar protic solvent component having a boiling point between 50 °C and 150 °C, a dielectric constant between 5 and 80.

21. The treatment composition of claim 20 wherein the polar protic solvent component is 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.4222. The treatment composition of claim 20 or 21 wherein the polar protic solvent component is selected from the group consisting of methanol, ethanol, propanol, isopropanol, acetic acid, propanoic acid and mixtures thereof, and mixtures thereof.

23. The treatment composition of claim 20, wherein the inorganic strong base component is selected from the group consisting of sodium hydroxide, potassium hydroxide, magnesium hydroxide, calcium hydroxide and mixtures thereof.

24. The treatment composition of claim 20, wherein the inorganic strong base component is present in the treatment composition in an amount sufficient to provide a pH greater than 10.

25. The treatment composition of claim 20, wherein crude oil in the crude oil material has an API value between less than 30° API and a sulfide compound content present in the crude oil in the crude oil material at a concentration between 1000 ppm and 40,000 ppm.

26. The process of any one of claims 17 to 19 further comprising harvesting electrons generated during the process and providing electrical power to a well field or an electrical grid.43

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