METHODS FOR REMOVING METALS AND CATIONS THEREOF FROM OIL-BASED FLUIDS

Abstract

An effective amount of a hydrazine complexing agent and/or a non-hydrazine complexing agent may be added to an oil-based fluid having at least one metal. The complexing agent may form an insoluble metal complex with the metal(s). The metal(s) may be or include, but are not limited to zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof. The insoluble metal complex may be or include, but is not limited to a zinc complex, a nickel complex, an iron complex, and combinations thereof. The insoluble metal complex may be removed from the oil-based fluid where the metal may be separated from the insoluble metal complex.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a Continuation-in-Part and claims priority to U.S. application Ser. No. 14/063,188 filed on Oct. 25, 2013; which claims priority to U.S. Provisional Application Ser. No. 61/720,025 filed on Oct. 30, 2012; all of which are incorporated by reference herein in their entirety.

FIELD OF THE INVENTION

The present invention relates to adding an effective amount of a hydrazine complexing agent and/or non-hydrazine complexing agent to an oil-based fluid having at least one metal and/or metal cation to form an insoluble metal complex with the metal and/or metal cation, and the insoluble metal complex may be removed from the oil-based fluid.

BACKGROUND

Oil-based fluids may have metal or metal cations therein, which may cause issues during refining or processing of the oil-based fluid if the metal or metal cation is not removed. Such oil-based fluids may be or include crude oil, a refinery fluid, a production fluid, a drilling fluid, a completion fluid, a fracturing fluid, a servicing fluid, a stimulation fluid, a treating fluid, and combinations thereof.

“Oil-based fluid” are fluids having a non-aqueous continuous phase where the non-aqueous continuous phase is all oil, a water-in-oil emulsion, or a brine-in-oil emulsion. In oil-based downhole fluids, solid particles may be suspended in a continuous phase consisting of oil. Water or brine may be emulsified in the oil; therefore, the oil is the continuous phase. The oil may consist of any oil or water-immiscible fluid that may include, but is not limited to, diesel, mineral oil, esters, refinery cuts and blends, or alpha-olefins. Oil-based fluid as defined herein may also include synthetic-based fluids or muds (SBMs), which are synthetically produced rather than refined from naturally-occurring materials. Synthetic-based fluids often include, but are not necessarily limited to, olefin oligomers of ethylene, esters made from vegetable fatty acids and alcohols, ethers and polyethers made from alcohols and polyalcohols, paraffinic, or aromatic, hydrocarbons alkyl benzenes, terpenes and other natural products and mixtures of these types.

Formation damage involves undesirable alteration of the initial characteristics of a producing formation, typically by exposure to drilling fluids, completion fluids, or in the production phase of the well. If the fluid formulations used in drilling, completion, production, or remediation operations are not engineered according to the need for the specific application, the effective permeability and pore volume of the producible formation in the near-wellbore region tend to decrease.

Drilling fluids are also referred to as drilling muds. Drilling fluids are any number of liquid and gaseous fluids and mixtures of fluids and solids (as solid suspensions, mixtures and emulsions of liquids, gases and solids) used in operations to drill boreholes into the earth.

There are a variety of functions and characteristics that are expected of completion fluids. The completion fluid may be placed in a well to facilitate final operations prior to initiation of production. Such final operations include, but are not necessarily limited to, setting screens, production lines, packers and/or downhole valves, and shooting perforations into the producing zones. The completion fluid assists with controlling a well if downhole hardware should fail, and the completion fluid does this by minimizing damage of the producing formation or completion components. Completion operation may include perforating the casing, setting the tubing and pumps in petroleum recovery operations. Both workover and completion fluids are used in part to control well pressure, to prevent the well from blowing out during completion or workover, or to prevent the collapse of well casing due to excessive pressure build-up.

Chemical compatibility of the completion fluid with the reservoir formation and other fluids used in the well is key to avoid formation damage. Chemical additives, such as polymers and surface active materials are known in the art for being introduced to the well servicing fluids for various reasons that include, but are not limited to, increasing viscosity, and increasing the density of the fluid. Water-thickening polymers serve to increase the viscosity of the fluid and thus lift drilled solids from the well-bore. The completion fluid is usually filtered to a high degree to reduce the amount of solids that would otherwise be introduced to the near-wellbore area. A regular drilling fluid is usually not compatible for completion operations mainly because of its solid content.

Production fluids also have a multitude of functions and characteristics necessary for carrying out the production of the well. As used herein, the terms produced fluids and production fluids refer to liquids and/or gases removed from a subsurface formation, including, for example, an organic-rich rock formation. Said differently, a production fluid is any fluid that comes out of a well, i.e. produced from the well. Produced fluids may include both hydrocarbon fluids and non-hydrocarbon fluids. Production fluids may include, but are not limited to, pyrolyzed shale oil, synthesis gas, a pyrolysis product of coal, carbon dioxide, hydrogen sulfide, and water (including steam). Produced oil quality, overall production rate, and/or ultimate recoveries may be altered by altering the production fluid. Generally, all precautionary means may be taken to assure that the production flow from the well is uninterrupted or said differently, to maintain the flow assurance of the well, such as preventing asphaltenes deposition, wax deposition, and/or hydrates from forming within the production fluids.

The resulting hydrocarbon stream from a producing well is a mixture that must be separated into its gross components, such as oil, gas, and water. The phases of the hydrocarbon stream must also be separated; i.e. the liquids from the vapors. Two-phase separators separate phases only, such as the vapor from the liquid. Three-phase separators are necessary when the production fluid also contains water that must be removed. Separators are classified by shape, such as vertical separators and horizontal separators. When the gas-oil ratio is very low, a vertical separator is preferred. Horizontal separators should be used when the volume of the gas or liquid is very large. Once the hydrocarbon stream goes through the separator, the resultant production streams are processed according to whether it is a gas stream or an oil stream. Crude oil may be a component within a production fluid that is separable therefrom.

The processing of gas removes hydrogen sulfide (H₂S), water (H₂O), and carbon dioxide (CO₂). Amine treaters can be used to reduce the CO₂, and H₂S. The water may be removed from the gas by using a glycol treater or a desiccant. The processing of crude oil involves removing contaminants, such as sand, salt, H₂O, sediments, and other contaminants. However, H₂O is the largest contaminant in oil or gas. Several units may be employed to remove such contaminants from the oil stream. A heater-treater may be used to break up the oil-H₂O emulsion. A free-water knockout vessel separates free water from the oil stream produced from the well. An electrostatic heater treater employs an electric field to separate the water from the oil stream by attracting the electric charge of the water molecules. Demulsifying agents may be used to break emulsions by use of chemicals.

Servicing fluids, such as remediation fluids, workover fluids, and the like, have several functions and characteristics necessary for repairing a damaged well. Such fluids may be used for breaking emulsions already formed. The terms “remedial operations” and “remediate” are defined herein to include a lowering of the viscosity of gel damage and/or the partial or complete removal of damage of any type from a subterranean formation. Similarly, the term “remediation fluid” is defined herein to include any fluid that may be useful in remedial operations.

Before performing remedial operations, the production of the well must be stopped, as well as the pressure of the reservoir contained. To do this, any tubing-casing packers may be unseated, and then servicing fluids are run down the tubing-casing annulus and up the tubing string. These servicing fluids aid in balancing the pressure of the reservoir and prevent the influx of any reservoir fluids. The tubing may be removed from the well once the well pressure is under control. Tools typically used for remedial operations include wireline tools, packers, perforating guns, flow-rate sensors, electric logging sondes, etc.

The development of suitable fracturing fluids is a complex art for use with hydraulic fracturing to improve the recovery of hydrocarbons from the formation. Once hydraulic fracturing begins, and the crack or cracks are made, high permeability proppant, relative to the formation permeability, is pumped into the fracture to prop open the crack. When the applied pump rates and pressures are reduced or removed from the formation, the crack or fracture cannot close or heal completely because the high permeability proppant keeps the crack open. The propped crack or fracture provides a high permeability path connecting the producing wellbore to a larger formation area to enhance the production of hydrocarbons.

The fracturing fluids must simultaneously meet a number of conditions. For example, they must be stable at high temperatures and/or high pump rates and shear rates that can cause the fluids to degrade and prematurely settle out the proppant before the fracturing operation is complete. Various fluids have been developed, but most commercially used fracturing fluids are aqueous based liquids that have either been gelled or foamed. When the fluids are gelled, typically a polymeric gelling agent, such as a solvatable polysaccharide, e.g. guar and derivatized guar polysaccharides, is used. The thickened or gelled fluid helps keep the proppants within the fluid. Gelling can be accomplished or improved by the use of crosslinking agents or cross-linkers that promote crosslinking of the polymers together, thereby increasing the viscosity of the fluid. One of the more common cross-linked polymeric fluids is borate cross-linked guar.

An oil-based refinery fluid or feed is defined as any oil-based fluid where the fluid is further refined or has been further refined, e.g. additives may be added to a crude oil or compounds may be removed from the crude oil at a refinery. Such fluid may be considered a crude oil and a refinery fluid. Refinery fluids are typically associated with refining oil and/or gas fluids.

It would be desirable if metals and/or metal ions could be removed from oil-based fluids.

SUMMARY OF THE INVENTION

There is provided, in one form, a method for removing metals from an oil-based based fluid by adding an effective amount of hydrazine to an oil-based fluid to form an insoluble metal complex, such as but not limited to, a zinc hydrazine complex, a nickel hydrazine complex, an iron hydrazine complex, and combinations thereof. The oil-based fluid may have or include at least one metal, such as but not limited to, zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof.

There is further provided, in another form, a method for removing metals from an oil-based fluid by adding an effective amount of a non-hydrazine complexing agent to an oil-based fluid to form an insoluble metal complex, such as but not limited to, a zinc metal complex, a nickel metal complex, an iron metal complex, and combinations thereof. The oil-based fluid may have or include at least one metal, such as but not limited to zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof. The non-hydrazine complexing agent may be or include, but is not limited to amine compounds, analogs, and combinations thereof. The amine compound may be or include monodentate, bidentate, or poly dentate amine compounds. The analog may be or include an amino-ether analog, an amino-alcohol analog, an amino-ketone analog, a phosphorous analog, and combinations thereof.

The complexing agent(s), i.e. hydrazine and/or non-hydrazine agents may inactivate and/or remove the metal(s) from the oil-based fluid.

DETAILED DESCRIPTION OF THE INVENTION

It has been discovered that an effective amount of hydrazine (H₂N—NH₂) or non-hydrazine complexing agent may be added to an oil-based fluid to form an insoluble metal complex. The oil-based fluid may have or include at least one metal, such as but not limited to zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof. The insoluble metal complex may be or include, but is not limited to, a zinc metal complex, a nickel metal complex, an iron metal complex, and combinations thereof. The insoluble metal complex may then be removed from the oil-based fluid.

The effective amount of the hydrazine may range from about 10 wt % to about 50 wt %, alternatively from about 20 wt % to about 40 wt %. And in one such embodiment, the amount may be about 35 wt %.

The molar ratio of hydrazine to the metal(s) may range from about one to about three moles of hydrazine to about one mole of the metal(s). In a non-limiting example, it may be desirable to use from about 2.0 to about 3.0 moles of hydrazine for each mole of metal present in the oil-based fluid to be treated. If less metal is present in the oil-based fluid, less hydrazine may be added to the fluid.

The non-hydrazine complexing agent may be or include, but is not limited to, monodentate, bidentate, or poly dentate amine compounds. Such amine compounds may be or include ethylenediamine (EDA), diethylenetriamine (DETA), trithethylenetetramine (TETA), tetraethylenepentamine (TEPA), aminoethylethanolamine (AEEA), diethanol amine (DEA), diethyl amine, hexamethyltetraamine, monoethyl amine, poly amines, and mixtures thereof. Other non-hydrazine complexing agents may be or include analogs, such as but not limited to an amino-ether analog, an amino-alcohol analog, an amino-ketone analog, a phosphorus analog, and combinations thereof.

In another non-limiting embodiment, the non-hydrazine complexing agent may be immobilized onto a substrate, such as but not limited to, nanoparticles, zeolites, polymer chains, solid substrates, and mixtures thereof. Nanoparticles have at least one dimension less than or equal to 999 nm; alternatively, the average particle size of nanoparticles is less than or equal to 999 nm.

Non-limiting embodiments of the nanoparticles may be or include nanotubes. Non-limiting embodiments of zeolites may be or include naturally occurring, synthetic, and combinations thereof. Non-limiting embodiments of the polymer chains may be or include anionic, cationic and nonionic, and combinations thereof.

In a non-limiting embodiment, the hydrazine may be used in combination with the non-hydrazine complexing agent to remove the metal(s). Alternatively, the non-hydrazine complexing agent is not used in combination with the hydrazine.

The oil-based fluid including the insoluble metal complex may be subjected to flocculation/coagulation prior to removing the insoluble metal complex. An additive may be added to the oil-based fluid to assist the flocculation/coagulation. Non-limiting examples of the additive may be or include, but are not limited to nonionic, cationic, amphoteric and anionic polymers; lime; alum; ferric sulfate; and mixtures thereof.

The removing of the insoluble metal complex from the oil-based fluid may occur by a process, such as but not limited to filtering, centrifugation, settling, and combinations thereof. Then, the metal may be separated from the insoluble metal complex to form a reusable metal. The separation may be performed in any way known to be useful to those of ordinary skill in the art. In a non-limiting example, the insoluble metal complex may be treated with a peroxide to produce a reusable metal salt, such as zinc bromide in a non-limiting embodiment. The reusable metal may then be added to another oil-based fluid, or even the same oil-based fluid if so desired.

‘Removing’ is defined herein to include any physical or chemical process to decrease the ability of the insoluble metal complex to contaminate the oil-based fluid. In other words, the insoluble metal complex may still be physically present in the oil-based fluid but chemically unable to react with other compounds in the oil-based fluid. Such chemical inactivation of the metal within the insoluble metal complex, as well as the insoluble metal complex, is considered ‘removed’ from the oil-based fluid for purposes herein.

‘Reusable’ as used herein is defined to mean that the metal(s) may be used as salts to mix with water to create a brine suitable as a drilling fluid, such as a zinc bromide brine. The reusable metal(s) may also be used for creating brines that may be or include calcium bromide, sodium bromide, calcium chloride, and combinations thereof. Alternatively, the hydrazine and/or the non-hydrazine complexing agent may be reusable once the complexing agent has been separated from the insoluble metal complex.

The oil-based fluid may be or include, but is not limited to, crude oil, a refinery fluid, a production fluid, a drilling fluid, a completion fluid, a fracturing fluid, a servicing fluid, a stimulation fluid, a treating fluid, and combinations thereof.

EXAMPLES

The following examples are provided to illustrate the present invention. The examples are not intended to limit the scope of the present invention, and they should not be so interpreted.

Example 1

A crude oil sample was mixed with a brine in a 50/50 by volume ratio. The crude oil contained 0.22% asphaltenes, and the brine included 14.22 ppg zinc bromide brine. The brine contained 5.00 wt % zinc, 9.63 wt % calcium, 32.31 wt % bromide, and 9.15 wt % chloride. The pH of the brine was 5.7 and had a TCT/LCTD of −7/5° F. The crude oil was mixed with the brine for 1 minute and placed in a 180° F. convection oven for 30 minutes to break any emulsion tendencies. At 30 minutes the brine and crude appeared to be completely separate from each other. After the crude-brine mixture cooled, the oil layer was titrated for zinc.

The titration occurred according to the following procedure:

• • Weigh out a sample in an Erlenmeyer flask. The sample size should range from about 3 to about 4 grams for a zinc concentration less than 500 ppm.
  • Add an amount of distilled or deionized (DI) water to the flask in an amount ranging from about 25 to about 100 mL and mix well.
  • Add four drops of Xylenol orange indicator to the flask and mix well. The solution should have a deep purple color.
  • Add HCl acid until the color turns bright yellow and mix well.
  • Add from about 5 to about 6 drops of HMT indicator until a purple-red color develops and mix solution well. The HMT indicator was prepared my mixing 50 grams of methenamine in 140 grams of DI water.
  • Titrate the sample with 0.05 m EDTA slowly; as the purple-red color fades to a dull red color, three additional drops of HMT were added to the solution to turn the color back to the purple-red color. Continue to titrate with 0.05 m EDTA until the solution turns from a purple-red color to a bright yellow color.

To assure that the endpoint has been reached, add 2 to 3 drops of HMT indicator. If the solution remains yellow, the endpoint has been reached. However, if the solution turns a purple-red color, continue titrating with 0.05 M EDTA until the endpoint is reached.

Record the amount of EDTA in mL used to reach the endpoint.

The percent of zinc by weight in the sample may be calculated by using the following formula:

% Zinc=N×V×6.538/sample weight

Zinc, ppm=% Zinc×10,000

• • Where:
  • N=normality of EDTA used (e.g. 0.05 M)
  • V=volume of EDTA used
  • Sample weight=weight of sample weighed out in grams

The zinc concentration of the crude oil before contamination with the brine was determined to be zero, and the zinc concentration after contamination with the brine was determined to be about 435 ppm.

If hydrazine hydrate interferes with the titration procedure or contains traces amount of zinc, then it should be subtracted from the zinc results to provide an accurate zinc concentration. Hydrazine hydrate (35% hydrazine) was titrated for zinc and was determined to contain 216 ppm of zinc. The test was repeated by mixing 10 mL of DI water with 10 mL of 35% hydrazine. After the titration, it was determined that the mixture contained 112 ppm of zinc; additional titrations were repeated to give nearly identical results at around 120 ppm.

Another test was done with 2.5 mL of 35% hydrazine mixed with 22.5 ml of DI water and was determined to contain 20 ppm of zinc. Then the data was plotted and was shown to give a linear relationship described by Equation 1 with a R̂2 of 0.9988

Equation 1 may be used to correct for actual zinc concentration when using hydrazine hydrate (35% hydrazine). Equation 1 is:

Zinc Interference, ppm in Zinc Out=6.2353×(Wt. % Hydrazine)

Example 2

Since titrating crude oil for zinc may take as long as 24 hour or more, titrating the water phase that is mixed with the crude oil is another option. Therefore, a mixture of 50% of the 55% hydrazine hydrate in water solution, and 50% of the crude oil was mixed for 1 minute and allowed to remain quiescent for 30 minutes. A complete separation of the hydrazine hydrate and the crude oil was observed. The water phase was titrated to contain 335 ppm of zinc. Since hydrazine interfered with the titration method by 216 ppm for this example, the actual amount of zinc that was removed was 119 ppm (335−216=119 ppm).

In the foregoing specification, the invention has been described with reference to specific embodiments thereof, and has been described as effective in providing methods for removing metals from an oil-based fluid. However, it will be evident that various modifications and changes can be made thereto without departing from the broader spirit or scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, specific complexing agents, non-hydrazine complexing agents, oil-based fluids, metals, and additives falling within the claimed parameters, but not specifically identified or tried in a particular composition or method, are expected to be within the scope of this invention.

The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. For instance, the method for removing metals from an oil-based fluid may consist of or consist essentially of adding an effective amount of hydrazine to an oil-based fluid to form an insoluble metal complex, such as but not limited to, a zinc hydrazine complex, a nickel hydrazine complex, an iron hydrazine complex, and combinations thereof; the oil-based fluid may have or include at least one metal, such as but not limited to, zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof.

Alternatively, the method for removing metals from an oil-based fluid may consist of or consist essentially of adding an effective amount of a non-hydrazine complexing agent to an oil-based fluid to form an insoluble metal complex, such as but not limited to, a zinc metal complex, a nickel metal complex, an iron metal complex, and combinations thereof; the oil-based fluid may have or include at least one metal, such as but not limited to zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof; the non-hydrazine complexing agent may be or include, but is not limited to amine compounds, analogs, and combinations thereof; the amine compound may be or include monodentate, bidentate, or poly dentate amine compounds; the analog may be or include an amino-ether analog, an amino-alcohol analog, an amino-ketone analog, a phosphorous analog, and combinations thereof.

The words “comprising” and “comprises” as used throughout the claims, are to be interpreted to mean “including but not limited to” and “includes but not limited to”, respectively.

Claims

1. A method for removing metals from an oil-based fluid comprising:

adding an effective amount of hydrazine to an oil-based fluid to form an insoluble metal complex selected from the group consisting of a zinc hydrazine complex, a nickel hydrazine complex, an iron hydrazine complex, and combinations thereof; wherein the oil-based fluid comprises at least one metal selected from the group consisting of zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof.

2. The method of claim 1 wherein the effective amount of the hydrazine ranges from about 10 wt % to about 50 wt %.

3. The method of claim 1 wherein a molar ratio of hydrazine to the at least one metal ranges from about one to about three moles of hydrazine to about one mole of the at least one metal.

4. The method of claim 1 further comprising physically removing the insoluble metal complex from the oil-based fluid.

5. The method of claim 4, wherein the physically removing the insoluble metal complex occurs by a process selected from the group consisting of filtering, centrifugation, settling, and combinations thereof.

6. The method of claim 4 further comprising subjecting the oil-based fluid comprising the insoluble metal complex to flocculation and/or coagulation prior to removing the insoluble metal complex.

7. The method of claim 6, wherein an additive selected from the group consisting of nonionic, cationic, amphoteric, and anionic polymers; lime; alum; ferric sulfate; and

mixtures thereof is added to the oil-based fluid in an amount effective to assist the flocculation/coagulation.

8. The method of claim 1 wherein the insoluble metal complex is reusable.

9. The method of claim 1, wherein the oil-based fluid is selected from the group consisting of crude oil, a refinery fluid, a production fluid, and combinations thereof.

10. The method of claim 1, wherein the oil-based fluid is selected from the group consisting of a drilling fluid, a completion fluid, a fracturing fluid, a servicing fluid, a stimulation fluid, a treating fluid, and combinations thereof.

11. The method of claim 1, wherein the oil-based fluid further comprises an effective amount of a non-hydrazine complexing agent to form the insoluble metal complex.

12. A method for removing metals from an oil-based fluid comprising:

adding an effective amount of a non-hydrazine complexing agent to an oil-based fluid to form an insoluble metal complex selected from the group consisting of a zinc metal complex, a nickel metal complex, an iron metal complex, and combinations thereof; and wherein the oil-based fluid comprises at least one metal selected from the group consisting of zinc metal, nickel metal, iron metal, cations thereof, and combinations thereof; and wherein the non-hydrazine complexing agent is selected from the group consisting of monodentate, bidentate, or poly dentate amine compounds; amino-ether, amino-alcohol, amino-ketone, and phosphorous analogs; and combinations thereof.

13. The method of claim 12, wherein the monodentate, bidentate, or poly dentate amine compounds are selected from the group consisting of ethylenediamine (EDA), diethylenetriamine (DETA), trithethylenetetramine (TETA), tetraethylenepentamine (TEPA), aminoethylethanolamine (AEEA), diethanol amine (DEA), diethyl amine, hexamethyltetraamine, monoethyl amine, poly amines, and mixtures thereof.

14. The method of claim 12, wherein the non-hydrazine complexing agent is immobilized onto a substrate.

15. The method of claim 14, wherein the substrate is selected from the group consisting of nanoparticles, zeolites, polymer chains, solid substrates, nanotubes, and mixtures thereof.

16. The method of claim 12, further comprising physically removing the insoluble metal complex from the oil-based fluid.

17. The method of claim 12, wherein the physically removing the insoluble metal complex occurs by a process selected from the group consisting of filtering, centrifugation, settling, and combinations thereof.

18. The method of claim 17 further comprising subjecting the oil-based fluid comprising the insoluble metal complex to flocculation and/or coagulation prior to removing the insoluble metal complex.