Gelling agents-based formulations and methods for managing the hydrate deposition in oil and gas pipelines

Abstract

Methods and formulations for managing the hydrate deposition and growth in oil and gas pipelines have been disclosed. Herein, the effective hydrate-inhibiting / anti-agglomerating formulations comprising combinations of polysaccharides / gelling agents along with the specific solvation packages in precise ratios contribute to managing the hydrophobic, hydrophilic, or amphiphilic nature of the formulations as per the requirement of production fluids / hydrate former compositions. These formulations are easily biodegradable, non-corrosive, and environmentally friendly.

Description

[0001] GELLING AGENTS-BASED FORMULATIONS AND METHODS FOR MANAGING THE HYDRATE DEPOSITION IN OIL AND GAS PIPELINES

[0002] FIELD OF THE INVENTION

[0003] The present invention relates to the new gelling agent-based formulations with various compositions that specifically prevent agglomeration, deposition, or growth of gas hydrate crystals in oil and gas pipelines in a multiphase system. Particularly, the invention discloses the method of preparing these new gelling agent -based formulations and their compositions while optimizing their hydrophobic, hydrophilic, or amphiphilic nature. More particularly, their performance was tested in simulated field conditions and a method of managing hydrate deposition in a multiphase system is offered in this invention.

[0004] BACKGROUND OF THE INVENTION

[0005] Gas hydrates are ice-like crystalline compounds that can form / deposit into the oil and gas pipelines during production or transport of the hydrocarbon fluid at suitable pressure and temperature conditions. Typical natural gas compositions like CH4, C2H6, C3H8, C4H10, C5H12, CO2, N2, H2S, etc., can form gas hydrate crystals in oil and gas transmission lines / operations, which can create serious operational and safety risks, as an uncontrolled pressure build-up may rupture the pipeline.

[0006] The injection of high dosages (20-40 wt% with respect to the aqueous content) of antifreeze chemicals like methanol and ethylene glycols, also called thermodynamic hydrate inhibitors (THIs), is one of the typical hydrate inhibition approaches in oil and gas industries. It is a highly energy and cost-intensive approach. The usage of low-dosage hydrate inhibitors (LDHIs) with effective dosages ranging from 0.1 to 5 wt% would be the most effective alternative to THIs. LDHIs can reduce the hydrate formation kinetics called kinetic hydrate inhibitors (KHIs) and / or prevent the agglomeration of hydrate crystals called hydrate anti-agglomerates (AAs).

[0007] High cost, low performance at high sub-cooling / high water-cut, and environmentally harmful / toxicity, are some of the major challenges associated with the current LDHIs. Therefore, it is necessary to develop / deploy new effective LDHIs. Therefore, the present invention provides effective and environmentally friendly hydrate - inhibiting formulations comprising gelling agents (e.g., galactomannan polysaccharides, glycoproteins, N-acetyl-D-glucosamine, L-rhamnose or D-glucuronic acid-based polysaccharides, polymers of arabinose, galactose, and a mixture thereof), polar and non-polar solvents (hexane, heptane, toluene, xylene, glycols, butyl glycol ethers etc.), or a mixture thereof.

[0008] Reference may be made to US Patent 7879767B2, granted to Baker Hughes Holdings LLC wherein the company has claimed a gelled aqueous viscoelastic treating fluid comprising of three components: (a) an aqueous base fluid (from halide salts of alkali metals and alkali earth metals, formate salts), (b) a non-ionic amine oxide viscoelastic surfactant (VES) gelling agent and (c) additives belonging to the group of polyamines, polyvinyl alcohols, polycaprolactams and mixtures thereof. The proportion of additives in the claimed formulation ranges from 0.1 to about 4.0 wt %. The patent further claims that the said gelled- viscoelastic treating fluid has the property of identical fluid containing additives from the group consisting of glycols, amines, polyglycerin, xylitol and mixtures thereof and both. This patent disclosed the hydrate inhibition in terms of a shift in thermodynamic hydrate phase equilibrium, not disclosing any kinetic inhibition and hydrate anti-agglomerating characteristic of their additives.

[0009] Reference may be made to patent application CN107035967A filed by Changzhou University, China, which disclosed compound anti-agglomerates of gas hydrate containing glucose, lignin amine and polycarboxylate, which is used in petroleum works technical field. In the claimed invention the disclosed anti-agglomerates contain 5-25% glucose, l%-5% lignin amine, and 1%- 5% polycarboxylate, and the remaining is distilled water. This patent disclosed the hydrate inhibition for CO2 hydrates only, not claiming any anti-agglomerating effect for natural gas hydrates.

[0010] Reference may be made to CN103261149B filed by ChampionX LLC which disclosed the composition and method for reducing hydrate agglomeration using Beta-amino ester surfactant. E.g. 3-(3-(dimethylamino) propylcarbamic) propionic acid 2-ethylhexyk, N, N-dimethyl butyrate - 1-amine., 3-(3-(dibutylamino) propylcarbamic) propionic acid 2-ethylhexyl., N-butyl-N-(3-(3-(2- ethyl hexyl oxy)-3-oxopropyl is amino) propyl group) fourth- 1 -amine acetate. And at least one solvent selected from Virahol, methyl alcohol, ethanol, 2-Ethylhexyl Alcohol, heavy aromatic petroleum naphtha, toluene, ethylene glycol, ethylene glycol monobutyl ether (EGMBE), diethylene glycol monoethyl ether, dimethylbenzene and its combination. Dosage range being applied was in the range of 0.1 % to 0.25 %. The main focus of this patent is on amine or quaternary ammonium salt-based additives only; gelling agent-based formulations were not disclosed.

[0011] Reference may be made to Russian Patent RU2715582C2, wherein hydrogel containing hydrate inhibitor having at polymer hydrogel particle (average diameter of 10-2000 mcm) with hydrogel content 50 to 100 %, thermodynamic hydrate inhibitor, kinetic hydrate inhibitor (e.g. N-vinyl pyrrolidone, N-vinyl caprolactam, vinyl caprolactam, vinyl pyrrolidone, vinyl piperidone, acryloylpyrrolidamine, acryloylpyrrolidamine, acryloylpyrrolidamine, acryloylpyrrolidol amide, acryloylpyrrolid amide, acryloylpyrrolid amide, acryloylpyrrolid amide, acryloylpyrrolid amide, acryloylpyrrolidamide, methyl N- vinylace tamide) or a combination thereof, were disclosed as hydrate inhibitors. This patent is not claiming any polysaccharides in their formulations.

[0012] Reference may be made to Das et al. (DOI: 10.1016 / j.petrol.2022.111156), wherein L-ascorbic acid as a green low-dosage hydrate inhibitor in water-based drilling fluid for the drilling of gas hydrate reservoirs was discussed. They discussed the hydrate inhibition for Tetrahydrofuran (THF) hydrates only, not claiming any anti-agglomerating effect for natural gas hydrates.

[0013] Reference may be made to Gupta and Sangwai (doi.org / 10.1021 / acs.energyfuels.9b01204), wherein oilfield polymers, such as polyacrylamide (PAM), xanthan gum (XG), and guar gum (GG) were used as low-dosage hydrate inhibitor. They discussed the kinetics of methane hydrate formation and dissociation but did not disclose the hydrate anti-agglomerating characteristic in multiphase systems of oil and gas pipelines.

[0014] Reference may be made to Effendi et al.(DGI: 10.1007 / sl3202-022-01477-2), Where the use of polysaccharides extracted from Tamar indusindica L. as natural kinetic hydrates inhibitor was disclosed. This study suggests that polysaccharides have a high potential to inhibit hydrates by delaying the induction time longer with a lower concentration (0.25 wt%) relatively, giving it an economic edge compared to the conventional kinetic inhibitor. However, in this article, kinetics data is not presented. Further, it does not claim any anti-agglomerating effect for natural gas hydrates. Reference may be made to Singh and Suri articles (doi.org / 10.1021 / acs.energyfuels.2c01062; doi.org / 10.1021 / acs. energyfuels.3c00674; doi.org / 10.1021 / acs.energyfuels.3c00065), wherein plant-based polysaccharides (e.g. pectin; k-carrageenan; lambda carrageenan blended with 4- methyl- 1 -pentanol or MEG; and guar gum) were investigated as synergists with kinetic hydrate inhibitors (e.g polyvinylpyrrolidone, polyvinylcaprolactam, Luvicap55w, and HIOP). They did not disclose any hydrate anti- agglomerating characteristic in multiphase systems.

[0015] Overall, the prior art reports clearly reveal that the invention as a whole i.e. formulation / composition comprising of the specific combination of the gelling agents along with suitable polar / non-polar solvents to manage / prevent the hydrate deposition in oil and gas pipelines, is not anticipated in any of the cited and analyzed prior art documents, Though, some reports are available on the use of polysaccharides on hydrate inhibitions, no report disclose their hydrate antiagglomerating characteristic in multiphase systems (oil-water-gas) occurring in oil and gas pipelines. Our formulations are optimized for the hydrophobicity, hydrophilicity, or amphiphilic nature of the hydrate formers and production fluids as per their requirement. Hence, it is advantageous to utilize these formulations and methods for managing the hydrate deposition in any oil and gas pipelines based on their fluid properties.

[0016] OBJECTIVES OF THE INVENTION

[0017] The main objective of this invention is to develop new formulations / methods that effectively prevent the agglomeration of hydrate particles by reducing the rate and fraction of gas hydrates formed into the liquid hydrocarbon phase and particularly in a multiphase system.

[0018] SUMMARY OF THE INVENTION

[0019] The present invention provides for effective hydrate-inhibiting formulations comprising gelling agents (e.g., galactomannan polysaccharides, N-acetyl-D-glucosamine, L-rhamnose or D- glucuronic acid based polysaccharides), polar and non-polar solvents (methanol, mono ethylene glycol, hexane, heptane, toluene, xylene, glycols, butyl glycol ethers, DMSO etc.), or a mixture thereof, In an embodiment, the present invention enhanced the interaction of active components (inhibitors) with the hydrate formers / liquid hydrocarbon phase while optimizing the formulations for their hydrophobic, hydrophilic, or amphiphilic nature.

[0020] In another embodiment, the enhanced hydrophilic nature of our formulations binds the water molecules intensely at hydrate forming temperature of -275K and pressure range of 4-10 MPa. The hydrophilic formulations inhibit hydrate formation while disrupting the local water structures required for cage formation.

[0021] In yet another aspect of the present invention, the hydrophobic and amphiphilic nature of our formulations would help in the dispersion of hydrate particles in the liquid hydrocarbon phase and enhance the hydrate anti-agglomerating characteristics of formulations.

[0022] In yet another embodiment, the compositions contain 0.1 -2 wt% formulation with respect to the aqueous phase with different compositions of solvents.

[0023] In yet another embodiment, the aqueous phase comprises the produced water (saline water) / seawater of various salinities. Additional features and embodiments of the present disclosure will be better understood through the techniques and other aspects of the disclosure. Other embodiments of the invention are described in detail herein and are considered a part of the claimed disclosure. Accordingly, to accomplish the objectives, the present invention provides new formulations and their application as LDHIs.

[0024] In an aspect, the present invention provides the development of various formulations comprising;

[0025] (a) 10-50 wt% gelling agents;

[0026] (b) 50-90 wt% solvents or THIs.

[0027] In an embodiment of the present invention, the organic solvents are selected from the groups consisting of hydrophobic, hydrophilic, or amphiphilic nature functionalities.

[0028] In yet another embodiment of the present invention, the said gelling agents are selected from the following polysaccharides classes - (i) Galactomannan polysaccharide

[0029] (ii) D-glucuronic acid-based polysaccharides

[0030] (iii) N-acetyl-D-glucosamine polysaccharide

[0031] (iv) Cellulose derivatives

[0032] In yet another embodiment, the present invention details the process for the preparation of the formulations comprising of;

[0033] (i) Mixing the gelling agents in different ratios to amphiphilic solvent (AM) and stirring the same for 10-15 min at a temperature ranging from 20 to 30°C;

[0034] (ii) Adding the gelling agent to the salt (ratio of salt and amphiphilic solvent is 1:1) while stirring for 5-30 min at a temperature ranging from 20 to 30°C;

[0035] (iii) Preparing another formulation by mixing the hydrophilic solvent (HP) to the gelling agents in 1: 1 ratio by stirring it for a period in the range of 10 to 20 minutes at the temperature ranging from 20 to 30°C;

[0036] (iv) For the development of another formulation, the gelling agent is again added to the hydrophobic solvents (HPO) in 1:1 ratio and stirring it to 10-20 minutes at a temperature ranging from 20 to 30°C. wherein

[0037] AM is selected from the group of solvents consisting of both hydrophobic and hydrophilic ends.

[0038] HP is selected from the group of hydrophilic solvents that consists of hydroxyl group;

[0039] HPO is selected from the group of hydrophobic solvents with a longer hydrocarbon part.

[0040] (v) The formulation obtained in step (iii) is homogenized by a high-speed homogenizer at 2500 RPM at a temperature ranging from 20 to 30°C, followed by the addition of amphiphilic solvent or THIs drop wise to form another formulation; In yet another embodiment, the formulation is applied to various water cuts (60-80%) of oil and aqueous phase at high pressure of natural gas and pure methane (simulating the field conditions).

[0041] In yet another embodiment, the proposed formulation reduces the hydrate fraction in the fluid by 65-75% and also diminishes the resistance to flow that occurs from hydrate crystals by 85-90% and forms a flowable hydrate slurry.

[0042] BRIEF DESCRIPTION OF THE DRAWINGS

[0043] FIG. 1. illustrates the comparison of water-to-hydrate conversion for the experiment performed with and without additive formulation (F-l) at 60 water cuts using the natural gas mixture as a hydrate former at -275 K and 6.0 MPa pressure.

[0044] FIG. 2. illustrates the comparison of absolute motor toque for the experiment performed with and without additive formulation (F-l) at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure.

[0045] FIG. 3. illustrates the comparison of water-to-hydrate conversion for the experiment performed with and without additive formulation (F-3) at 60 water cuts using the natural gas mixture as a hydrate former at -275 K and 6.0 MPa pressure.

[0046] FIG. 4. illustrates the comparison of absolute motor toque for the experiment performed with and without additive formulation (F-3) at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure.

[0047] FIG. 5. illustrates the visual observations obtained during the natural gas hydrate formation for the experiments conducted with 60 water cuts and with / without additive formulation-3.

[0048] FIG. 6. illustrates the comparison of water-to-hydrate conversion for the experiment performed with and without additive formulation (F-4) at 60 water cuts using the natural gas mixture as a hydrate former at -275 K and 6.0 MPa pressure.

[0049] FIG. 7. illustrates the comparison of absolute motor torque for the experiment performed with and without additive formulation (F-4) at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure.

[0050] FIG. 8. illustrates the water to hydrate conversion% and absolute motor torque for the experiment performed with formulation (F-5) at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure. FIG. 9. illustrates the water to hydrate conversion% and absolute motor torque for the experiment performed with formulation (F-7) at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure.

[0051] FIG. 10. illustrates the water to hydrate conversion% and absolute motor torque for the experiment performed with formulation (F-8) at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure.

[0052] FIG. 11. illustrates the comparison of absolute motor toque for the experiment performed with and without additive formulations (F-8, F-10, F-l 1) at 80 water cut using the pure methane as a hydrate former at -275K and 6.0 MPa pressure.

[0053] FIG. 12. illustrates the comparison of water to hydrate conversion % for all the formulation with no additive test at 60 water cut using the natural gas mixture as a hydrate former at -275K and 6.0 MPa pressure.

[0054] FIG. 13. illustrates the comparison of absolute motor toque for the experiment performed with and without additive formulation (F-l to F14) at 60 water cut using the natural gas mixture as a hydrate former at -275 K and 6.0 MPa pressure.

[0055] DETAILED DESCRIPTION OF THE INVENTION

[0056] The foregoing detailed description of the disclosure is elaborated to provide a clear understanding to the person who is skilled in the art. Additional features, embodiments and advantages of the invention will be described hereinafter which form the subject of the claims of the disclosure, However, the set forth disclosure provide in the specification will best be understood in conjunction with the appended claims and FIGs as provide heretofore. It should be appreciated by those skilled in the art that the conception and specific embodiment disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present disclosure. It should also be realized by those skilled in the art that such equivalent processes do not depart from the spirit and scope of the disclosure as set forth in the appended claims. It will be readily understood that the aspects of the present disclosure, as generally described herein, and illustrated in the FIGs, can be arranged, substituted, combined, and designed in a wide variety of different configurations, all of which are explicitly contemplated and make part of this disclosure.

[0057] While the invention has been disclosed with reference to certain embodiments, it will be understood by those skilled in the art that various changes may be made, and equivalents may be substituted without departing from the scope of the invention. In addition, many modifications may be made to adapt to a particular situation or material to the teachings of the invention without departing from its scope.

[0058] Throughout the specification and claims, the following terms take the meanings explicitly associated herein unless the context clearly dictates otherwise. The meanings of "a", "an", and "the" include plural references. The meaning of "in" includes "in" and "on." Referring to the drawings, like numbers indicate like parts throughout the views. Additionally, a reference to the singular includes a reference to the plural unless otherwise stated or inconsistent with the disclosure herein.

[0059] In line with the above objectives, the present invention provides low-dosage gelling agents-based formulations and a method to prevent agglomeration, deposition, or growth of gas hydrate crystals in oil and gas pipelines in a multiphase (oil-water-gas) system.

[0060] The details of the specific and enabled combinations of polysaccharides / gelling agents, along with the specific solvents contributing to increasing the hydrophobic, hydrophilic, or amphiphilic interaction, preventing the hydrate agglomeration in gas-liquid hydrocarbon. The method for the synthesis of the gelling agent based formulations comprises;

[0061] (i) Mixing the gelling agents in different ratios to amphiphilic solvent (AM) and stirring the same for 10-15 min at a temperature ranging from 20 to 30°C;

[0062] (ii) Adding the gelling agent to the salt (ratio of salt and amphiphilic solvent is 1:1) while stirring for 5-30 min at a temperature ranging from 20 to 30°C;

[0063] (iii)Preparing another formulation by mixing the hydrophilic solvent (HP) to the gelling agents in 1: 1 ratio by stirring it for a period in the range of 10 to 20 minutes at the temperature ranging from 20 to 30°C;

[0064] (iv)For the development of another formulation, the gelling agent is again added to the hydrophobic solvents (HPO) in 1: 1 ratio and stirring it to 10-20 minutes at a temperature ranging from 20 to 30°C;

[0065] (v) The formulation obtained in step (iii) is homogenized by a high-speed homogenizer at 2500 RPM at a temperature ranging from 20 to 30°C, followed by the addition of amphiphilic solvent or THIs dropwise to form another formulation. Different classes of polysaccharides selected as the gelling agent with different solvents or THIs to design new formulations that act as LDHI and are listed as follows-

[0066] (a) To develop formulation- 1 (F-l), a class of polysaccharides (for example, Galactomannan polysaccharides or D-glucuronic acid-based polysaccharides, or N-acetyl-D-glucosamine polysaccharide) along with the hydrophilic solvent or THIs and synthesis steps aforementioned, are applied;

[0067] (b)The formulation-2 (F-2) was prepared using the polysaccharides chosen in step (a) along with a hydrophobic solvation package using the synthesis steps aforementioned;

[0068] (c)The formulation-3 (F-3) was prepared using the gelling agent of steps (a) and (b) with an amphiphilic solvent while applying the aforementioned synthesis procedure;

[0069] (d)The formulation-4 (F-4) discloses the interaction of salts with the formulation prepared in step (c);

[0070] (e)The formulation-5 (F-5) was prepared using the substituted aromatic hydrocarbon as a hydrophobic moiety along with the gelling agent of step (a);

[0071] (f) Formulation 6 and 7 (F-6 and F-7) disclose the interaction of the hydroxyl moiety (hydrophilic solvent or THI comprising a hydroxyl group) and salts (Like NaCl), respectively, with the gelling agent of step (a);

[0072] (g)The formulation-8 (F-8) was prepared using the gelling agent of steps (a) and (b) with apolar aprotic solvent in a ratio of 1:4 while applying the aforementioned synthesis procedure;

[0073] (h) The formulation-9 (F-9) discloses the interaction of salts with the formulation prepared in the step (g);

[0074] (i) The formulation- 10 (F-10) was prepared using the gelling agent of step (a) and (b) with an amphiphilic and polar aprotic solvent (as of step g) while applying the aforementioned synthesis procedure; (j) The formulation- 11 (F-l 1) was prepared using the gelling agent of steps (a) and (b) with a polar aprotic solvent and hydrophilic solvent or THIs while applying the aforementioned synthesis procedure;

[0075] (k) The formulation- 12 (F-12) was prepared using the cyclic non-polar solvent as a hydrophobic moiety along with the gelling agent of step (a);

[0076] (l) The formulation- 13 (F-13) was prepared using the solvent having phenolic lipids, with anacardic acid, cardol, and cardanol along with the gelling agent of step (a).

[0077] (m) The formulation- 14 (F-14) was prepared using one of the polysaccharides (D-glucuronic acid) chosen in step (a) along with a hydrophobic solvation package using the synthesis steps aforementioned.

[0078] In yet another aspect of the present invention, a high-pressure visual torque reactor setup consisting of a high-pressure rector coupled with a motor torque sensor, a recirculating water bath, a gas panel, and a data acquisition system was used to provide the evidence of hydrate-in-oil slurry, wall deposition, or hydrate plug formation through motor torque signal and visual observation.

[0079] The reactor is made up of SS-316, with the total internal volume of the reactor being around 515 cm3. The reactor is equipped with two sapphire windows (10mm x 70mm) fixed at the front and back. An overhead stirrer coupled with a magnetic drive *4 horsepower motor was installed on the top of the reactor (speed range of 100-1500 RPM). This motor is coupled with a torque sensor, which is able to measure torque within the range of 60-100 N.cm with ±0.05 N.cm resolution.

[0080] A Four-blade vane and baffle impeller geometry stirrer are employed for the adequate mixing of the reactor content, which generates a turbulent flow similar to the pipeline.The reactor is equipped with pressure transducers (0-200bar range and uncertainty of ±0.1%), pressure gauge and temperature sensor (Pt- 100, uncertainty of ±0.1 °C).

[0081] The reactor is connected with a gas panel having a gas inlet valve and a Gas outlet valve / Vent needle valve with a high-pressure quick connector stem with a maximum pressure limit of 200 bar. A safety relief valve is connected to the reactor, which is set at 105 bar pressure. A recirculating water bath was connected to the cooling jacket of the reactor to maintain the desired temperature of the reactor content. A manual camera is installed in front of the sapphire window for visual observations during hydrate formation.

[0082] Approximately 140 mL sample was loaded into the reactor. This sample was sufficient to submerge the complete impeller geometry and corresponds to the liquid loading of 27%.

[0083] In yet another aspect of the present invention, a synthetic natural gas mixture and pure methane (99.99%) of the following specification was used as a hydrate former:

[0084] Table 1: Synthetic natural gas mixture used for hydrate formation

[0085] The reactor was purged 2-3 times with natural gas or pure methane to remove any air present inside. Now, reactor content was cooled to the desired experimental temperature (-275K), and mixing was commenced at 500 rpm. After achieving the desired pipeline temperature, the reactor was pressurized to the experimental pressure (~6.0 MPa). Hydrate formation was confirmed in this step.

[0086] All the hydrate formation experiments were performed in batch mode and water to hydrate conversion was measured using mole calculation (based on pressure drop) and hydrate number of 6.1.

[0087] After completion of the hydrate formation step, the reactor was heated to 298 K temperature, which confers the complete hydrate dissociation and pressure recovery to the initial injection pressure. The pressure, temperature, absolute torque signals profile, and visuals were recorded throughout the experiments. EXAMPLES

[0088] The following examples, which include preferred embodiments, will serve to illustrate the practice of this invention, it being understood that the particulars shown are by way of example and for purpose of illustrative discussion of preferred embodiments of the invention. This invention involves the development of various formulations for the prevention of gas hydrate formation and its agglomeration or growth. The prepared formulations were further utilized as the low dosage gas hydrate inhibitors (LDHIs). The present invention is further explained with reference to the following Examples 1-14 are given by way of illustration and, therefore, should not be construed to limit the scope of the present invention.

[0089] Example 1

[0090] Synthetic natural gas mixture and pure methane used for hydrate formation and assess the performance of LDHIs via isothermal method had the composition as shown above in Table 1.

[0091] Isothermal method:

[0092] • To understand the performance of our LDHIs at constant temperature / sub-cooling, experiments were also performed using the isothermal method.

[0093] • A predetermined amount of water for different water cut system (112ml for 80WC and 84 ml for 60WC), Paraffin oil (28ml for 80WC and 56ml in 60WC), and our LDHIs (0.5- 1.5wt%) were loaded in high-pressure visual reactor which corresponds to a total liquid volume of ~140mL.The gas to liquid ratio was approximately 2.7: 1.0.

[0094] • In step 1, the isothermal conditions were maintained by cooling of the reactor at 1.0 ±0.5 °C by using a recirculating chiller.

[0095] • When the reactor temperature is achieved, the reactor is pressurized to 60±1.0 bar, and the liquid was stirred at 400rpm.

[0096] • The pressure and temperature profile obtained during hydrate formation by the addition of 0.5-1.5wt% of our LDHIs / formulations along with morphological observations recorded throughout the reaction.

[0097] • After step 1, the reactor was set to 25±0.5°C to dissociate the formed hydrate (hydrate dissociation step) The results obtained from the experiments performed via isothermal method for Natural gas mixture and pure methane are presented as the amount of hydrate formed (water to hydrate conversion %). To probe the anti-agglomerating characteristics of the synthesized formulations, we measured the resistance-to-flow build due to the formation of hydrate-in-oil slurry. The resistance-to-flow was correlated with the motor torque data which further can be correlated with the pipeline differential pressure generated due to hydrate deposition / blockage.

[0098] The absolute motor torque data obtained with natural gas as the hydrate former and with our formulations depicts the reduction of torque signals to about 85-90% (negligible increase in torque) which validates the anti-agglomerating characteristics of the formulations. In terms of amount of hydrate formed as we can see that in case of baseline (without additive) is -38% but with the addition of 0.5-1.5wt% of the formulations, amount of hydrate is reduced to -12%. Hereby the reduction in the amount of hydrate formed is -65-75% (Refer to Table 2).

[0099] In case of pure methane as the hydrate former and with our formulations, the absolute motor torque is reduced to about -65-70% validates the flowable form of hydrates (Refer to Table 3). Tables 2 and 3 correspond to the water to hydrate conversion % and torque data obtained at different water cuts by using natural gas and pure methane as hydrate formers, respectively.

[0100] Table 2: Summary of tests conducted using isothermal method, test conditions and test results at 60 water-cut using NG mixture as hydrate former.

[0101] * Water to Hydrate conversion% % data for hydrate growth phase as the end of hydrate formation test

[0102] Pexp: Experimental Pressure

[0103] TeXp: Experimental Temperature #Subcooling Temperature = Equilibrium temperature-experimental temperature

[0104] Equilibrium Temperature: 15.85 °C at 60 bar

[0105] Table 3: Summary of tests conducted using isothermal method, test conditions and test results at 80 water-cut using pure methane gas as hydrate former.

[0106] *Water to Hydrate conversion % data for hydrate growth phase (-70-100 min data)

[0107] Pexp: Experimental Pressure

[0108] TeXp: Experimental Temperature

[0109] #Subcooling Temperature = Equilibrium temperature-experimental temperature

[0110] Equilibrium Temperature: 8.5 °C at 60 bar

[0111] T-l: Trial- 1; T-2: Trial-2

[0112] Example 2: Hydrate formation kinetics for formulation F-l

[0113] FIG. 1 illustrates the comparison plot of water-to-hydrate conversion for the independent experiments performed to probe the effect of formulation (F-l) on the kinetics of natural gas hydrate formation at 60water cut, 6 MPa pressure and -275K temperature. As can be seen from FIG., approximately 40% hydrate was formed in the baseline (without additive) trial, which was reduced to 10% with the addition of 0.5wt% of formulation F-l.

[0114] Example 3: Resistance to flow measurements during hydrate formation for formulation F- 1:

[0115] FIG. 2 illustrates the comparison plot of absolute motor torque for the independent experiments performed to probe the effect of another formulation F-l on the agglomeration of hydrate crystals (resistance to flow measurements) at 60water cut, 6 MPa pressure and -275 K temperature

[0116] As can be seen in the FIG., the absolute motor toque signals increase with the hydrate growth and reach -20 N.cm for the baseline trials in just 30 minutes of hydrate formation time, which indicates the formation of hard hydrate crystals or agglomeration of hydrate particles. This indicates the plugging scenario in the pipeline.

[0117] With the addition of 0.5 wt% of formulation F-l, the motor torque signals were significantly reduced initially (3-4Ncm), while after 80 min, hydrate agglomeration and wall deposition were observed, which led to an increase in the motor torque signals around 5 Ncm. Example 4: Hydrate formation kinetics for formulation F-3

[0118] FIG. 3 illustrates the comparison plot of water-to-hydrate conversion for the independent experiments (repeated trials) performed to probe the effect of one of our formulations (F-3) on the kinetics of natural gas hydrate formation at 60water cut. As can be seen from FIG., approximately 40% hydrate was formed in the baseline (without additive) trials, which was reduced to 10% with the addition of 0.5wt% of formulation F-3. The results for F-2 formulation is almost similar to that of F-l and F-3. -75% reduction in the hydrate content is observed with 0.5 wt% of formulation F- 3. Independent repeated trials have also shown in the FIG.

[0119] Example 5: Resistance to flow measurements during hydrate formation for formulation F-3

[0120] FIG. 4 illustrates the comparison plot of absolute motor torque for the independent experiments performed to probe the effect of one of our formulations (F-3) on the agglomeration of hydrate crystals (resistance to flow measurements) at 60water cut.

[0121] As can be seen in the FIG., the absolute motor toque signals increase with the hydrate growth and reach -20 N.cm for the baseline trials in just 30 minutes of hydrate formation time, which indicates the formation of hard hydrate crystals or agglomeration of hydrate particles.

[0122] With the addition of 0.5 wt% of formulation F-3, the motor torque signals were significantly reduced or not increased (3-4Ncm). It confers that hydrate crystals are fully dispersed in the liquid phase and have no agglomeration.

[0123] Example 6: Visual observations of hydrate growth for formulation F-3

[0124] FIG. 5 illustrates the comparison visuals captured for the independent experiments performed to understand the crystal growth behavior at 60 water cut.

[0125] FIG. 5 illustrates that in the absence of additives, hard ice-like crystals start to grow / agglomerate in the bulk liquid phase. However, with the addition of our formulation, the formation of hydrate slurry formation (no hard plug) is observed.

[0126] This example illustrates the visual observations of the aforementioned tests illustrating the substantial reduction in the hydrate crystal growth. Example 7: Hydrate formation kinetics for formulation F-4

[0127] FIG. 6 illustrates the comparison plot of water-to-hydrate conversion for the independent experiments performed to probe the effect of another formulation (F-4) on the kinetics of natural gas hydrate formation at 60water cut, 6 MPa pressure and -275K temperature. As can be seen from FIG., approximately 40% hydrate was formed in the baseline (without additive) trials, which was reduced to ~9% with the addition of 1.0 wt% of formulation F-3. >75% reduction in the hydrate content is observed with 1.0 wt% of formulation F-3 with salts.

[0128] Example 8: Resistance to flow measurements during hydrate formation for formulation F-4

[0129] FIG. 7 illustrates the comparison plot of absolute motor torque for the independent experiments performed to probe the effect of another formulation F-4 on the agglomeration of hydrate crystals (resistance to flow measurements) at 60water cut, 6 MPa pressure and -275K temperature

[0130] As can be seen in the FIG., the absolute motor toque signals increase with the hydrate growth and reach ~20 N.cm for the baseline trials in just 30 minutes of hydrate formation time, which indicates the formation of hard hydrate crystals or agglomeration of hydrate particles.

[0131] With the addition of 1.0 wt% of formulation F-4 with salts, no increase in the motor torque signals were observed throughout the experimental run. It confers the anti-agglomerating characteristic of our formulation.

[0132] Example 9: Hydrate formation kinetics and Resistance to flow measurements during hydrate formation for formulation F-5

[0133] FIG. 8 illustrates the data plot of water-to-hydrate conversion and absolute motor torque for the independent experiments performed to probe the effect of another formulation (F-5) on the kinetics of natural gas hydrate formation at 60water cut, 6 MPa pressure and -275K temperature. As shown in FIG. 1, approximately 40% hydrate was formed in the baseline (without additive) trials, which was reduced to ~11% with the addition of 1.0 wt% of formulation F-5 (refer to FIG. 8). Moreover, >75% reduction in the hydrate content is observed with 1.0 wt% of formulation F-5 compared to the baseline presented above. With the addition of 1.0 wt% of formulation F-5, no increase in the motor torque signals were observed throughout the experimental run. It validates the antiagglomerating characteristic of our formulation.

[0134] Example 10: Hydrate formation kinetics and Resistance to flow measurements during hydrate formation for formulation F-7

[0135] FIG. 9 illustrates the data plot of water-to-hydrate conversion and absolute motor torque for the independent experiment performed to probe the effect of another formulation (F-7) on the kinetics of natural gas hydrate formation at 60water cut, 6 MPa pressure and -275K temperature. As shown in FIG. 1, approximately 40% hydrate was formed in the baseline (without additive) trials, which was reduced to -14% with the addition of 1.0 wt% of formulation F-7(similar trend is seen with F-6).

[0136] Moreover, -65% reduction in the hydrate content is observed with 1.0 wt% of formulation F-7 compared to the baseline presented in example 3.

[0137] With the addition of 1.0 wt% of formulation F-7, the motor torque signals were maximum increased to about 4 throughout the experimental run. This negligible increase in torque signals validates the anti-agglomerating characteristic of our formulation. The water to hydrate conversion % and absolute motor Torque data for F-6 and F-7 is almost similar.

[0138] Example 11: Hydrate formation kinetics and Resistance to flow measurements during hydrate formation for formulation F-8

[0139] FIG. 10 illustrates the data plot of water-to-hydrate conversion and absolute motor torque for the independent experiment performed to probe the effect of F-8 on the kinetics of natural gas hydrate formation at 60water cut, 6 MPa pressure and -275K temperature. With the addition of 1.5wt% of formulation F-8, the water to hydrate conversion was reduced to -14%, in baseline it was -40%.

[0140] Moreover, -65% reduction in the hydrate content is observed with 1.0wt% of formulation F-8 compared to the baseline data.

[0141] With the addition of 1.0 wt% of formulation F-7, the motor torque signals were maximum increased to about 4 throughout the experimental run. Negligible increase in torque signals validates the anti-agglomerating characteristic of our formulation. In another formulation F-9, the hydrate formation kinetics as well as on the absolute motor torque were almost similar to the F-8 with natural gas mixture as a hydrate former.

[0142] Example 12: Resistance to flow measurements during hydrate formation for formulation F- 8, F-10,F-ll using methane gas as hydrate former

[0143] FIG. 11 illustrates resistance-to-flow build due to the formation of hydrate-in-oil slurry which represents the anti-agglomerating characteristics of our formulations. In FIG.11, we measured the motor torque data and correlated these torque signals to the resistance-to-flow mimicking oil and gas pipelines. FIG.l 1 illustrates the comparison plot of absolute motor torque for the independent experiments performed to probe the effect of different formulations F-8,F-10,F-l l on the agglomeration of hydrate crystals (resistance to flow measurements) at 80water cut, 6 MPa pressure and -275K temperature using pure methane gas as the hydrate former.

[0144] As can be seen in the FIG., the absolute motor toque signals increase with the hydrate growth and reach 12-14 N.cm (Refer to table 3) corresponds to the amount of hydrate formed about -30% for the baseline trials after 90 minutes of hydrate formation time, which indicates the formation of hard hydrate crystals or agglomeration of hydrate particles.

[0145] With the addition of 1.0wt% formulations, no increase in the motor torque signals were observed throughout the experimental run with - water to hydrate conversion 18% in F-8, 17% in F-10 and F-l l formulations. The anti-agglomerating characteristic of our formulations is validated by the torque signals.

[0146] As evident from FIG.11 , Our formulations reduced the hydrate agglomeration significantly for the fluid having 80 watercut and flowable hydrate slurry formed.

[0147] Example 13: Comparison of water to hydrate conversion % for all the formulations

[0148] Figure 12 illustrates the comparison plot of water-to-hydrate conversion for the independent experiments performed with various formulations (F-l to F-14) and no additive test at 60water cut, 6 MPa pressure, and -275K temperature. As can be seen from Fig, Formulations Fl to F-6 show the best results while reducing the hydrate conversion by -75% compared to the baseline (without additive) trial. Example 14: Comparison of resistance to flow measurements for all the formulations

[0149] Figure 13 illustrates the comparison plot of resistance to flow measurements for the independent experiments performed with various formulations (F-l to F-14) and no additive test at 60water cut, 6 MPa pressure, and -275K temperature. As can be seen from Fig, Formulations Fl to F-9 show the best results while reducing the absolute motor toque by 80-85% compared to the baseline (without additive) trial.

[0150] ADVANTAGES OF THE INVENTION

[0151] The industry’s current hydrate prevention strategy requires the injection of large quantities (20-40 wt% with respect to production water) of thermodynamic inhibitors (alcohols or glycols), which act as anti-freeze agents to destabilize hydrate crystals. The injection of these chemicals in subsea pipelines costs up to $30 per barrel of water produced; this cost structure means that fields in deep- water / ultradeep water and / or with large water fractions are often economically unviable. Therefore, a paradigm shift is required to move away from thermodynamic inhibitors and adopt a new class of low-dosage hydrate inhibitors (0.1-5 wt% with respect to production water). In this regard, the present invention offers two important advantages :- i. The claimed formulations are effective in a dosage ranging from 0.5-1.5wt%. Therefore, it will help lower the environmental carbon footprint and support the concept of long-subsea tiebacks. ii. The claimed formulations are easily biodegradable, non-corrosive, and environmentally friendly

[0152] The adoption of our formulations in offshore deep or ultra-deep-water gas field operations will improve market growth while enhancing natural gas production. The hydrate inhibitors market is expected to proliferate in the Asia Pacific, especially in India, as India’s new discoveries in deep / ultra-deep-water gas fields, including eastern and western offshore, account for the huge potential of natural gas.

Claims

We claim1. A low-dosage hydrate inhibitor formulation comprising: a. 10-50 wt% gelling agents; b. 50-90 wt% solvents or thermodynamic hydrate inhibitors (THIs); wherein said gelling agents are polysaccharides; and wherein said solvents are polar or non-polar solvents and are of hydrophobic, hydrophilic, or amphiphilic nature.

2. The formulation as claimed in claim 1, wherein the polysaccharides are selected from the groups consisting of galactomannan polysaccharide, D-glucuronic acid-based polysaccharides, N-acetyl-D-glucosamine polysaccharide, cellulose derivatives, or a mixture thereof.

3. The formulation as claimed in claim 1, wherein the solvents are selected from the groups consisting of hexane, heptane, toluene, xylene, glycols, butyl glycol ethers, DMSO or a mixture thereof.

4. A process for the preparation of the formulations as claimed in claim 1 , comprising the step of mixing a gelling agent in a solvent and stirring the mixture for 5-30 minutes at a temperature ranging from 20 to 30°C to form the formulation.

5. The process as claimed in claim 4, wherein the solvents are selected from the groups consisting of hydrophobic, hydrophilic, or amphiphilic solvents.

6. The process as claimed in claim 4, wherein the ratio of gelling agent and polar hydrophilic solvent (HP) is 1: 1 or 1:4, wherein the hydrophilic solvent is consisting of hydroxyl group or sulphoxide group.

7. The process as claimed in claim 4, wherein the ratio of gelling agent and hydrophobic solvent (HPO) is 1: 1, wherein the hydrophobic solvent is consisting of longer hydrocarbon part.

8. The process as claimed in claim 6, wherein the formulation obtained is homogenized by a highspeed homogenizer at 2500 RPM at a temperature ranging from 20 to 30°C, followed by addition of amphiphilic solvent or THIs dropwise to form another formulation, wherein the amphiphilic solvent is consisting of both hydrophobic and hydrophilic ends.

9. The process as claimed in claim 4, wherein the hydrophobic, hydrophilic, or amphiphilic solvents are selected depending on the composition of hydrate formers and production fluid.

10. The process as claimed in claim 9, wherein the fluid is made up of water cuts (60-80%) of oil- aqueous phase and natural gas mixture (multiphase system).

11. The process as claimed in claim 9, wherein the fluid contains produced water (saline water) or thermodynamic hydrate inhibitors (THIs) with hydroxyl groups.

12. The formulation as claimed in claim 1, wherein the formulation reduces the hydrate fraction in the fluid by 65-75% at -275 K temperature and pressure ranging from 4-6 MPa at a concentration ranging from 0.5-1.5wt%.

13. The formulation as claimed in claim 1, wherein the formulation diminishes the resistance to flow of hydrate crystals by 85-90% and forms a flowable hydrate slurry.

14. The formulation as claimed in claim 1, wherein the formulation prevents the agglomeration, or deposition and growth of hydrate particles in oil and gas pipelines under multiphase conditions.

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