Additives for well treatment, method for preparing well treatment compositions using these additives and use of said compositions

Abstract

A well treatment composition dewaxing additive for cleaning wells containing hydrocarbon waxes. The wax removal additive contains nano polysaccharide. A method of cleaning a hydrocarbon well containing at least one component of wax, asphaltene or scale by injecting a nanopolysaccharide solution.

Description

[0001] CROSS-REFERENCE TO RELATED APPLICATIONS

[0002] This patent application claims the benefit of U.S. Provisional Patent Application Serial No. 63 / 364,769, filed on May 16, 2022, which is incorporated herein by reference in its entirety. Background Art

[0003] Hydrocarbon fluids experience changes in pressure and temperature during production and transportation from the reservoir to the surface and then to the refinery. These changes, along with changes in operating conditions, can cause various components in the fluid (e.g., paraffins, asphaltenes, scale) to become unstable and precipitate. Under certain conditions, these precipitated components can present significant challenges to flow assurance, including, but not limited to, increased fluid viscosity and the deposition of solids on pipeline surfaces, containers, and other oilfield equipment. These in turn can lead to a number of operational challenges, such as pipeline flow restrictions, increased solids during pigging operations leading to reduced cleaning efficiency, or increased pipeline back pressure leading to reduced throughput. Various thermal, mechanical, and chemical methods are used to prevent and mitigate the precipitation and deposition of these components, thereby avoiding costly delays caused by their interference with production and transportation processes. These remedial methods include pigging or scraping, isolating equipment and flow lines to prevent heat loss, applying heat through heated liquids (e.g., hot oil or hot water), utilizing heat generation reactions, or applying inhibitors, dispersants, or solvents.

[0004] Paraffin wax precipitation and deposition and its impact on fluid flow in pipelines remains one of the biggest challenges facing the oilfield industry. The precipitation of paraffin wax (CnH2n+2) from hydrocarbons is primarily temperature dependent, but there are other parameters such as pressure that also affect the solubility of paraffin wax in hydrocarbon fluids and may cause its precipitation. To overcome these challenges, the oilfield industry has adopted various thermal, mechanical and chemical methods, including the use of paraffin wax inhibitors, pour point depressants, paraffin wax dispersants, paraffin wax solvents and combinations thereof.

[0005] The application of hot oil or hot water is one of the most commonly used techniques to remove deposited wax and asphaltene from hydrocarbon wells. Hot oil or hot water is circulated down the casing and back up the tubing to remove deposits from the wellbore. The hot water and oil melt the hydrocarbon deposits and then dissolve and / or disperse in the appropriate medium. Hot water primarily tends to soften the wax, thus making it easier to disperse and remove. Hot water is also used to effectively clean out pipelines before deploying pigs.

[0006] In the case of hot oil injection, the hot oil used can be injected from the bottom of the tank, because that is where the largest amount of wax and asphaltene is present. The hot oil is pumped down into the annulus, and when it reaches the formation, the oil loses most of its heat, so the "cooled" hot oil has a reduced ability to melt the wax in the crude oil.

[0007] Since the hot oil also contains dissolved wax from the casing, this wax may be transported into the formation and precipitate there, resulting in serious wax problems. A known solution is to add a wax dispersant to prevent the dissolved wax from redepositing.

[0008] Similarly, with hot water injection, hot water is pumped through the casing. However, when the hot water returns to the annulus, it has lost its energy, so the melted wax downhole may be deposited again in the wellbore. Therefore, it is not very effective. Adding a dispersant to the hot water can help keep the melted wax dispersed in the water. Therefore, in the case of a transport pipeline, pigging may be required to remove the remaining wax and asphaltene deposits. Summary of the invention

[0009] In various embodiments, a well treatment composition comprising a wax removal additive is provided for cleaning a well containing hydrocarbon wax.

[0010] In some embodiments, the wax removal additive is mixed in hot water to form a nanosuspension.

[0011] In some embodiments, the wax removal additive is mixed with hot water and at least one water-soluble solvent to form a nanosuspension. In many embodiments, the at least one water-soluble solvent comprises methanol, isopropanol, butanol, ethylene glycol, or aminobutyl ether.

[0012] In some embodiments, the wax removal additive includes nanopolysaccharides.

[0013] In some embodiments, the nanopolysaccharide accounts for 0.001 wt % to 3 wt % in the water system.

[0014] In some embodiments, the nanopolysaccharide comprises at least six carbon atoms.

[0015] In some embodiments, the nanopolysaccharide comprises nanocrystalline cellulose.

[0016] In some embodiments, the nanopolysaccharide comprises nanocrystalline cellulose with microfibrils.

[0017] In some embodiments, the nanopolysaccharide comprises at least one of sucrose, glucose, maltose, lactose, fructose, starch, glycogen, dextrin, inulin, cyclodextrin, or dextran.

[0018] In some embodiments, the nanopolysaccharide can be modified with at least one of styrene maleic anhydride, ethylene vinyl acetate, alkyl acrylate, polyisobutylene succinic anhydride or olefin maleic anhydride or a surfactant or a combination thereof. In many embodiments, the surfactant can include alkyl sulfonic acid, alkyl phosphoric acid or alkyl amine.

[0019] In various embodiments, the composition is used to clean process lines, storage tanks, and transportation lines.

[0020] In some embodiments, methods are provided for preparing a well treatment composition by mixing together the following ingredients to form a nanosuspension: at least one wax removal additive and at least hot water.

[0021] In one embodiment, the method may load the well treatment composition into a pigging manifold connected to and in fluid communication with the pipeline.

[0022] In one embodiment, the method may clean the pipeline by circulating a well treatment composition disposed within the pipeline.

[0023] In some embodiments, methods of cleaning hydrocarbon wells containing at least one of wax, asphaltene, or scale by injecting a nanopolysaccharide solution are presented.

[0024] In some embodiments, the method comprises injecting the nanopolysaccharide solution downhole in a hydrocarbon well and / or into the top surface of a flow pipe or storage tank or transport line.

[0025] In some embodiments, the method comprises injecting a polysaccharide solution suspended in at least hot water and removing wax from the wellbore or from a flow conduit or from a storage tank or from a transport line.

[0026] In some embodiments, the nanopolysaccharide solution is added as is or in a combined form.

[0027] In some embodiments, the method comprises adding a nano-polysaccharide solution of carbohydrate / polysaccharide fatty acid esters having a molecular weight between about 300 and 100,000 to a hydrocarbon well at a level of 0.1 wt % to 25 wt %. DETAILED DESCRIPTION

[0028] The following illustrative examples of the claimed subject matter will now be disclosed. For the sake of clarity, not all features of actual implementations are described in this specification. It should be understood that in the development of any such actual implementation, many implementation-specific decisions may be made to achieve the developer's specific goals, such as complying with system-related and business-related constraints, which will vary from implementation to implementation. Furthermore, it should be understood that such development efforts, even if complex and time-consuming, will be a routine task for those of ordinary skill in the art who benefit from this disclosure.

[0029] In addition, as used herein, the article "a" is intended to have its ordinary meaning in the patent field, that is, "one or more". In this article, the term "about" when applied to a value generally means within the tolerance range of the device used to produce the value, or in some examples, means ±10%, or ±5%, or ±1%, unless otherwise expressly specified. In addition, the term "substantially" as used herein refers to, for example, most, or almost all, or all, or an amount in the range of about 51% to about 100%. In addition, the examples herein are intended to be illustrative only and are presented for discussion purposes and not by way of limitation.

[0030] In one aspect, embodiments disclosed herein relate to or are directed to wax deposit removal compositions and / or wax deposit removal fluids, methods of preparing wax deposit removal compositions and / or wax deposit removal fluids, and / or methods of utilizing wax deposit removal compositions and / or wax deposit removal fluids in one or more applications in the oil and gas industry. The wax deposit removal compositions and / or wax deposit removal fluids are configured or adapted to clean wells containing hydrocarbon waxes.

[0031] The treatment fluid composition that can be used for removing wax from hydrocarbon wells described herein is an aqueous nano suspension of a wax removal material comprising a polysaccharide. The polysaccharide generally contains at least 6 carbon atoms. The polysaccharide may be or may comprise sucrose, glucose, maltose, lactose, fructose, starch, glycogen, dextrin, inulin, cyclodextrin, dextran, cellulose or a combination thereof. Any isomer and enantiomer of such polysaccharides and mixtures thereof will work. The polysaccharide may be or may comprise nanocrystalline cellulose, which may be in the form of microfibers. Generally speaking, the wax removal material herein may be used in a granular form, a fibrous form or a combination thereof. Any of the polysaccharides listed above may be modified by reaction with a hydroxyl-reactive molecule (such as a carboxylic acid, for example a fatty acid or an acid such as acetic acid and citric acid (such as cellulose acetate or cellulose citrate), anhydride, amine, alkylene oxide and / or ester). The polysaccharide may also be modified by mixing with a surfactant, a water-soluble solvent or other effective reagent (including the molecular types listed above), whether or not these reagents react with the hydroxyl groups of the polysaccharide. Examples of molecules that can be used with the polysaccharides herein include styrene maleic anhydride, ethylene vinyl acetate, alkyl acrylates, polyisobutylene succinic anhydride or olefin maleic anhydride or surfactants such as alkyl sulfonic acids, alkyl phosphoric acids, alkyl amines and alcohol ethoxylates. Examples of solvents that can be used as part of the treatment fluid include methanol, isopropanol, butanol, ethylene glycol or aminobutyl ether. Mixtures of these solvents can also be used.

[0032] The wax removal materials suitable for use in the methods described herein typically have a molecular weight of up to about 500,000 Daltons, such as 300 to 100,000 Daltons, as pure or modified polysaccharides. For example, fatty acid polysaccharide esters having a molecular weight of 300 to 100,000 Daltons may be used.

[0033] The above-mentioned wax removal material is usually dispersed in the aqueous medium with a concentration of 0.001 wt % to 3 wt % based on the total treatment fluid weight, such as 0.5 wt % to 2 wt %, for example 0.5 wt %, 1.0 wt %, 1.5 wt % or 2.0o wt %. Larger and smaller concentrations can also be used, and can also be effective. For example, a treatment fluid with up to 25 wt % of the wax removal material described herein can be used based on the weight of the treatment fluid, for example in the range of 0.1 wt % to 25 wt %. The size of the wax removal material is adjusted to nanometer level by stirring, shearing or other actions, so that larger particles are broken down into smaller particles. Can be sized before the wax removal material is added to the aqueous medium or after the wax removal material is added to the aqueous medium. The treatment fluid obtained is the nano suspension of the wax removal material in the aqueous medium.

[0034] Composition preparation

[0035] The wax deposit removal compositions and / or wax deposit removal fluids disclosed herein can be prepared using various ingredient percentages as described below:

[0036] Product A: Take 995g of distilled water and put it into a Weiss blender. Measure 5g of nanocrystalline cellulose, such as but not limited to CelluForce NCC NCV100-NASD90 provided by CelluForce, USA. Slowly add the nanocrystalline cellulose sample to the blender and mix it under high shear for about 2 minutes to make a uniform nano suspension. After mixing, take out the suspension and put it into a bottle and store it.

[0037] Product B: Take 990g of distilled water and put it into a Weiss blender. Measure 10g of nanocrystalline cellulose (NCC). Slowly add the NCC sample into the blender and mix under high shear for about 2 minutes to make a uniform nanosuspension. After mixing, take out the suspension and put it into a bottle and store it.

[0038] Product C: Take 985g of distilled water and put it into a Weiss blender. Measure 15g of nanocrystalline cellulose (NCC). Slowly add the NCC sample into the blender and mix under high shear for about 2 minutes to make a uniform nanosuspension. After mixing, take out the suspension and put it into a bottle and store it.

[0039] Product D: Take 980g of distilled water and put it into a Weiss blender. Measure 20g of nanocrystalline cellulose (NCC). Slowly add the NCC sample into the blender and mix under high shear for about 2 minutes to make a uniform nanosuspension. After mixing, take out the suspension and put it into a bottle and store it.

[0040] Determination of the melting point of wax deposits

[0041] The melting point / softening point of the wax deposit can be measured using a crossed polarized microscope. The sample can be placed in a glass plate cover with a glass slide and placed and heated to about 75°C. The temperature can be maintained at 75°C for about 5 minutes. The sample is then slowly cooled at a rate of 1°C / minute and the temperature at which the first wax crystals appear is recorded. The previous temperature will then become the melting point of the wax deposit.

[0042] Performance Testing

[0043] Performance testing of the wax deposit removal compositions and / or wax deposit removal fluids disclosed herein can be performed. About 2.0 g of wax deposits can be collected from the field and transferred to a 150 ml sani glass bottle. The sample can be heated in a water bath at the softening point temperature of the wax deposits for 30 minutes. After 30 minutes, the bottle can be removed from the water bath and the entire bottom of the bottle may be immediately coated with molten deposits. The bottle can be cooled to room temperature for about 1 hour so that all wax deposits solidify.

[0044] The bottle can then be shaken thoroughly and 100 g of the previously prepared product A, B, C or D nanosuspension can be slowly added. In another bottle containing 2.0 g of wax deposit, 100 g of deionized water can be added. All bottles can be placed in a water bath at a temperature about 5°C higher than the melting point of the wax deposit for about 30 minutes to ensure that all wax has melted.

[0045] After 30 minutes, all bottles can be removed from the water bath, shaken thoroughly for approximately 1 minute, placed on a workbench, and allowed to cool to ambient temperature for approximately 30 minutes.

[0046] After 30 minutes, the bottle can be shaken for about 30 seconds to pour out all the product containing suspended wax. Acetone can be added to the bottle and shaken thoroughly. All of the acetone can be slowly poured out and air-dried without removing any loose wax from the bottle. Any wax removed with acetone can be put back into the bottle before air-drying. The wax deposit remaining in the bottle can be recorded and the weight of wax removed and the percentage of wax removed calculated. The following table shows the results of this performance test.

[0047]

[0048] Oil and Gas Industry Applications

[0049] The wax deposit removal compositions and / or wax deposit removal fluids disclosed herein can be used or applied to at least one oil and gas industry application, and can achieve significantly improved results for at least one oil and gas industry application. At least one oil and gas industry application can be selected from downhole applications, wellbore fluid applications, fluid fracturing applications, pipeline applications, or at least one combination thereof. The wax deposit removal compositions and / or wax deposit removal fluids disclosed herein achieve surprising and unexpected performance results in at least one oil and gas industry application.

[0050] For general use downhole, the preparation of the treatment fluid is substantially as described above. It should be noted that any suitable water can be used to make the treatment fluid. That is, although the above examples are performed using distilled water, any reasonably available water that can be used can be used as a carrier medium for the treatment fluid. Thus, for example, produced water, groundwater, seawater, clean non-drinking water, etc. can be used alone or in combination. As described above, the wax removal material is dispersed in water together with any solvent to be used. The treatment fluid mixture can be subjected to high shear mixing to reduce the particle size in the treatment fluid, or the wax removal material can be ground or otherwise sized before being added to the treatment fluid.

[0051] The treatment fluid thus prepared is pumped downhole into the well, and the treatment fluid is optionally transported using a pipeline arranged in the well. The treatment fluid can be heated before it is pumped downhole to promote the removal of wax. In some cases, the aqueous medium can be heated before adding the wax removal material so that the wax removal material is added to the hot water medium (e.g., hot water) to help disperse and eventually remove the wax. If the melting temperature of the wax is known, and the use of the heated aqueous medium is not expected to affect the underground formation in an undesirable manner, the treatment fluid can be heated to a temperature close to the melting temperature of the wax. The treatment fluid can also be used at ambient temperature, although it is generally expected that heating to any degree will accelerate the removal of wax. In some cases, the treatment fluid can remain stationary in the well for a period of time to allow wax to leave the underground formation and enter the treatment fluid. By replacing the treatment fluid with another fluid (such as water, brine, drilling fluid, etc.), the treatment fluid with the removed wax is pumped to the ground. It should be noted that the treatment fluid here can also be used to remove hydrocarbon wax from equipment such as flow lines, pipelines (e.g., using a pig manifold to move the treatment fluid), storage tanks, pumps, mixers, instruments, and transportation equipment.

[0052] In some embodiments, waxy hydrocarbon wells are cleaned by wax deposit removal compositions and / or wax deposit removal fluids as described in the present disclosure, which can achieve significantly improved performance results for well cleaning applications such as, for example, well cleaning applications in the midstream (i.e., pipeline) market. The use of nano polysaccharides such as nanocrystalline cellulose makes the proposed wax deposit removal compositions and / or wax deposit removal fluids a sustainable alternative to known wax well treatment compositions. The treatment fluids and compositions described herein can also serve to remove asphaltene and scale from underground structures such as wells and the above-mentioned equipment.

[0053] Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications may be made in the example embodiments without materially departing from the present disclosure. Therefore, all such modifications are intended to be included within the scope of the present disclosure as defined in the appended claims. In the claims, means-plus-function clauses are intended to cover structures described herein as performing the recited functions, and not only structural equivalents, but also equivalent structures. Thus, while nails and screws may not be structural equivalents because nails employ cylindrical surfaces to secure wooden parts together and screws employ helical surfaces, nails and screws may be equivalent structures in the context of fastening wooden parts. It is the applicant's express intent not to invoke 35 U.S.C. §112(f) to make any limitations on any claim herein unless the phrase "means for..." and the associated function are expressly used in the claim.

Claims

1. A well treatment composition comprising a polysaccharide wax removal additive dispersed in an aqueous medium for cleaning a well containing hydrocarbon wax.

2. The well treatment composition according to claim 1, wherein The wax removal additive is mixed in hot water to form a nanosuspension.

3. The well treatment composition according to claim 1, wherein The wax removal additive is mixed with a combination of hot water and at least one water-soluble solvent to form a nanosuspension.

4. The well treatment composition according to claim 3, wherein: The at least one water-soluble solvent includes methanol, isopropanol, butanol, ethylene glycol or aminobutyl ether.

5. The well treatment composition according to claim 1, wherein The wax removal additive includes nano polysaccharide.

6. The well treatment composition according to claim 5, wherein The concentration of the nanopolysaccharide in the treatment composition is 0.001 wt % to 3 wt % of the treatment composition.

7. The well treatment composition according to claim 5, wherein: The nanopolysaccharide comprises at least six carbon atoms.

8. The well treatment composition according to claim 5, wherein: The nanopolysaccharide comprises nanocrystalline cellulose.

9. The well treatment composition according to claim 5, wherein: The nanopolysaccharide comprises nanocrystalline cellulose with microfibrils.

10. The well treatment composition according to claim 5, wherein: The nano polysaccharide comprises sucrose, glucose, maltose, lactose, fructose, starch, glycogen, dextrin, inulin, cyclodextrin, dextran or a combination thereof.

11. The well treatment composition according to claim 5, wherein: The nano polysaccharide is modified with styrene maleic anhydride, ethylene vinyl acetate, alkyl acrylate, polyisobutylene succinic anhydride, olefin maleic anhydride, surfactant or a combination thereof.

12. The well treatment composition according to claim 11, wherein The treatment composition includes a surfactant comprising an alkyl sulfonic acid, an alkyl phosphoric acid, an alkyl amine, or a combination thereof.

13. A method comprising using the composition of claim 1 to clean pipelines, storage tanks and transport lines.

14. A method comprising preparing a well treatment composition by mixing together a polysaccharide wax removal additive and hot water to form a polysaccharide nanosuspension.

15. The method of claim 14, further comprising loading the well treatment composition into a pigging manifold connected to and in fluid communication with the pipeline.

16. The method of claim 14, further comprising cleaning the tubing by circulating the well treatment composition disposed within the tubing.

17. A method of cleaning a hydrocarbon well containing at least one of wax, asphaltenes or scale by injecting an aqueous treatment fluid comprising nanopolysaccharides.

18. The method of claim 17, wherein: Injecting the treatment fluid comprising the nanopolysaccharide solution includes injecting the treatment fluid into a hydrocarbon well, a flow pipe, a storage tank, or a transportation pipeline.

19. The method of claim 17, comprising injecting the polysaccharide solution suspended in at least hot water and removing the wax from a wellbore or from a flow conduit or from a storage tank or from a transport line.

20. The method of claim 17, wherein: The polysaccharide is a fatty acid polysaccharide ester having a molecular weight of about 300 to 100,000 Daltons, and the concentration of the polysaccharide in the treatment fluid is 0.1 wt % to 25 wt % based on the weight of the treatment fluid.

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