CN116333698A - Hydrate inhibitor and preparation method and application thereof - Google Patents
Hydrate inhibitor and preparation method and application thereof Download PDFInfo
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- CN116333698A CN116333698A CN202310151994.6A CN202310151994A CN116333698A CN 116333698 A CN116333698 A CN 116333698A CN 202310151994 A CN202310151994 A CN 202310151994A CN 116333698 A CN116333698 A CN 116333698A
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- 239000003112 inhibitor Substances 0.000 title claims abstract description 78
- 238000002360 preparation method Methods 0.000 title abstract description 5
- 238000005553 drilling Methods 0.000 claims abstract description 36
- 125000000217 alkyl group Chemical group 0.000 claims abstract description 17
- -1 natural gas hydrates Chemical class 0.000 claims abstract description 10
- 239000012530 fluid Substances 0.000 claims description 24
- 238000000034 method Methods 0.000 claims description 24
- WQDUMFSSJAZKTM-UHFFFAOYSA-N Sodium methoxide Chemical group [Na+].[O-]C WQDUMFSSJAZKTM-UHFFFAOYSA-N 0.000 claims description 12
- 239000000178 monomer Substances 0.000 claims description 12
- 125000003178 carboxy group Chemical group [H]OC(*)=O 0.000 claims description 9
- 229940105325 3-dimethylaminopropylamine Drugs 0.000 claims description 8
- IUNMPGNGSSIWFP-UHFFFAOYSA-N dimethylaminopropylamine Chemical compound CN(C)CCCN IUNMPGNGSSIWFP-UHFFFAOYSA-N 0.000 claims description 8
- IPCSVZSSVZVIGE-UHFFFAOYSA-N hexadecanoic acid Chemical compound CCCCCCCCCCCCCCCC(O)=O IPCSVZSSVZVIGE-UHFFFAOYSA-N 0.000 claims description 8
- 238000004519 manufacturing process Methods 0.000 claims description 8
- 239000003054 catalyst Substances 0.000 claims description 7
- POULHZVOKOAJMA-UHFFFAOYSA-N dodecanoic acid Chemical compound CCCCCCCCCCCC(O)=O POULHZVOKOAJMA-UHFFFAOYSA-N 0.000 claims description 6
- 230000008569 process Effects 0.000 claims description 5
- 235000021314 Palmitic acid Nutrition 0.000 claims description 4
- QHJABUZHRJTCAR-UHFFFAOYSA-N n'-methylpropane-1,3-diamine Chemical compound CNCCCN QHJABUZHRJTCAR-UHFFFAOYSA-N 0.000 claims description 4
- WQEPLUUGTLDZJY-UHFFFAOYSA-N n-Pentadecanoic acid Natural products CCCCCCCCCCCCCCC(O)=O WQEPLUUGTLDZJY-UHFFFAOYSA-N 0.000 claims description 4
- 239000005639 Lauric acid Substances 0.000 claims description 3
- 235000021355 Stearic acid Nutrition 0.000 claims description 3
- QIQXTHQIDYTFRH-UHFFFAOYSA-N octadecanoic acid Chemical compound CCCCCCCCCCCCCCCCCC(O)=O QIQXTHQIDYTFRH-UHFFFAOYSA-N 0.000 claims description 3
- OQCDKBAXFALNLD-UHFFFAOYSA-N octadecanoic acid Natural products CCCCCCCC(C)CCCCCCCCC(O)=O OQCDKBAXFALNLD-UHFFFAOYSA-N 0.000 claims description 3
- 239000008117 stearic acid Substances 0.000 claims description 3
- GDFCSMCGLZFNFY-UHFFFAOYSA-N Dimethylaminopropyl Methacrylamide Chemical compound CN(C)CCCNC(=O)C(C)=C GDFCSMCGLZFNFY-UHFFFAOYSA-N 0.000 claims description 2
- PIICEJLVQHRZGT-UHFFFAOYSA-N Ethylenediamine Chemical compound NCCN PIICEJLVQHRZGT-UHFFFAOYSA-N 0.000 claims description 2
- PFKFTWBEEFSNDU-UHFFFAOYSA-N carbonyldiimidazole Chemical compound C1=CN=CN1C(=O)N1C=CN=C1 PFKFTWBEEFSNDU-UHFFFAOYSA-N 0.000 claims description 2
- 230000035484 reaction time Effects 0.000 claims description 2
- TUNFSRHWOTWDNC-HKGQFRNVSA-N tetradecanoic acid Chemical compound CCCCCCCCCCCCC[14C](O)=O TUNFSRHWOTWDNC-HKGQFRNVSA-N 0.000 claims description 2
- 239000002245 particle Substances 0.000 abstract description 45
- 230000002776 aggregation Effects 0.000 abstract description 15
- 238000004220 aggregation Methods 0.000 abstract description 13
- 239000007789 gas Substances 0.000 abstract description 13
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Natural products C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 abstract description 9
- 239000003345 natural gas Substances 0.000 abstract description 5
- 238000011161 development Methods 0.000 abstract description 2
- NMJORVOYSJLJGU-UHFFFAOYSA-N methane clathrate Chemical compound C.C.C.C.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O NMJORVOYSJLJGU-UHFFFAOYSA-N 0.000 description 30
- 239000006227 byproduct Substances 0.000 description 12
- 238000010438 heat treatment Methods 0.000 description 12
- 238000003756 stirring Methods 0.000 description 12
- 239000003921 oil Substances 0.000 description 11
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 11
- 230000002401 inhibitory effect Effects 0.000 description 9
- 235000019198 oils Nutrition 0.000 description 9
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 8
- 150000001875 compounds Chemical class 0.000 description 8
- 238000010992 reflux Methods 0.000 description 8
- ITNQWRBKRFXDGV-UHFFFAOYSA-N cyclopentane;hydrate Chemical compound O.C1CCCC1 ITNQWRBKRFXDGV-UHFFFAOYSA-N 0.000 description 6
- 230000000694 effects Effects 0.000 description 6
- 239000002002 slurry Substances 0.000 description 6
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 description 5
- 238000012360 testing method Methods 0.000 description 5
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 4
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical group [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 4
- 238000001816 cooling Methods 0.000 description 4
- 238000004821 distillation Methods 0.000 description 4
- 239000003365 glass fiber Substances 0.000 description 4
- 238000005259 measurement Methods 0.000 description 4
- 239000000203 mixture Substances 0.000 description 4
- 239000000376 reactant Substances 0.000 description 4
- 239000011780 sodium chloride Substances 0.000 description 4
- UOXJNGFFPMOZDM-UHFFFAOYSA-N 2-[di(propan-2-yl)amino]ethylsulfanyl-methylphosphinic acid Chemical compound CC(C)N(C(C)C)CCSP(C)(O)=O UOXJNGFFPMOZDM-UHFFFAOYSA-N 0.000 description 3
- SFHYNDMGZXWXBU-LIMNOBDPSA-N 6-amino-2-[[(e)-(3-formylphenyl)methylideneamino]carbamoylamino]-1,3-dioxobenzo[de]isoquinoline-5,8-disulfonic acid Chemical compound O=C1C(C2=3)=CC(S(O)(=O)=O)=CC=3C(N)=C(S(O)(=O)=O)C=C2C(=O)N1NC(=O)N\N=C\C1=CC=CC(C=O)=C1 SFHYNDMGZXWXBU-LIMNOBDPSA-N 0.000 description 3
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 3
- 125000003368 amide group Chemical group 0.000 description 3
- 238000003556 assay Methods 0.000 description 3
- 230000015572 biosynthetic process Effects 0.000 description 3
- 230000000903 blocking effect Effects 0.000 description 3
- 238000011156 evaluation Methods 0.000 description 3
- 230000005764 inhibitory process Effects 0.000 description 3
- 239000000314 lubricant Substances 0.000 description 3
- 239000013535 sea water Substances 0.000 description 3
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 description 2
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- RGSFGYAAUTVSQA-UHFFFAOYSA-N Cyclopentane Chemical compound C1CCCC1 RGSFGYAAUTVSQA-UHFFFAOYSA-N 0.000 description 2
- 239000008186 active pharmaceutical agent Substances 0.000 description 2
- 238000005054 agglomeration Methods 0.000 description 2
- 239000000440 bentonite Substances 0.000 description 2
- 229910000278 bentonite Inorganic materials 0.000 description 2
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 description 2
- GQOKIYDTHHZSCJ-UHFFFAOYSA-M dimethyl-bis(prop-2-enyl)azanium;chloride Chemical compound [Cl-].C=CC[N+](C)(C)CC=C GQOKIYDTHHZSCJ-UHFFFAOYSA-M 0.000 description 2
- 238000007598 dipping method Methods 0.000 description 2
- 238000003384 imaging method Methods 0.000 description 2
- 229910017053 inorganic salt Inorganic materials 0.000 description 2
- 230000003993 interaction Effects 0.000 description 2
- 239000007788 liquid Substances 0.000 description 2
- 239000001103 potassium chloride Substances 0.000 description 2
- 235000011164 potassium chloride Nutrition 0.000 description 2
- 125000002924 primary amino group Chemical group [H]N([H])* 0.000 description 2
- 239000000243 solution Substances 0.000 description 2
- 238000004781 supercooling Methods 0.000 description 2
- IAYPIBMASNFSPL-UHFFFAOYSA-N Ethylene oxide Chemical compound C1CO1 IAYPIBMASNFSPL-UHFFFAOYSA-N 0.000 description 1
- 239000004721 Polyphenylene oxide Substances 0.000 description 1
- 230000009471 action Effects 0.000 description 1
- 239000000654 additive Substances 0.000 description 1
- 230000000996 additive effect Effects 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 239000007864 aqueous solution Substances 0.000 description 1
- 125000002091 cationic group Chemical group 0.000 description 1
- 239000001913 cellulose Substances 0.000 description 1
- 229920002678 cellulose Polymers 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 239000003638 chemical reducing agent Substances 0.000 description 1
- 239000011248 coating agent Substances 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- 238000001514 detection method Methods 0.000 description 1
- 150000004985 diamines Chemical class 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 150000002148 esters Chemical class 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 239000000706 filtrate Substances 0.000 description 1
- DMEGYFMYUHOHGS-UHFFFAOYSA-N heptamethylene Natural products C1CCCCCC1 DMEGYFMYUHOHGS-UHFFFAOYSA-N 0.000 description 1
- 150000004677 hydrates Chemical class 0.000 description 1
- 230000002209 hydrophobic effect Effects 0.000 description 1
- 230000002706 hydrostatic effect Effects 0.000 description 1
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 1
- 238000009533 lab test Methods 0.000 description 1
- 239000010410 layer Substances 0.000 description 1
- 239000012669 liquid formulation Substances 0.000 description 1
- 238000007433 macroscopic evaluation Methods 0.000 description 1
- 238000003760 magnetic stirring Methods 0.000 description 1
- 239000000463 material Substances 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 239000002480 mineral oil Substances 0.000 description 1
- 235000010446 mineral oil Nutrition 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 229920000570 polyether Polymers 0.000 description 1
- 230000000379 polymerizing effect Effects 0.000 description 1
- 230000008092 positive effect Effects 0.000 description 1
- 238000010791 quenching Methods 0.000 description 1
- 230000000171 quenching effect Effects 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 150000003839 salts Chemical class 0.000 description 1
- 230000006641 stabilisation Effects 0.000 description 1
- 238000011105 stabilization Methods 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 239000002344 surface layer Substances 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 235000015112 vegetable and seed oil Nutrition 0.000 description 1
- 239000008158 vegetable oil Substances 0.000 description 1
- 238000005303 weighing Methods 0.000 description 1
- 239000000230 xanthan gum Substances 0.000 description 1
- 229920001285 xanthan gum Polymers 0.000 description 1
- 229940082509 xanthan gum Drugs 0.000 description 1
- 235000010493 xanthan gum Nutrition 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/02—Well-drilling compositions
- C09K8/03—Specific additives for general use in well-drilling compositions
- C09K8/035—Organic additives
-
- C—CHEMISTRY; METALLURGY
- C07—ORGANIC CHEMISTRY
- C07C—ACYCLIC OR CARBOCYCLIC COMPOUNDS
- C07C231/00—Preparation of carboxylic acid amides
- C07C231/02—Preparation of carboxylic acid amides from carboxylic acids or from esters, anhydrides, or halides thereof by reaction with ammonia or amines
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
- C09K2208/22—Hydrates inhibition by using well treatment fluids containing inhibitors of hydrate formers
Abstract
The invention relates to the technical field of petrochemical industry, and discloses a hydrate inhibitor and a preparation method and application thereof. The hydrate inhibitor is shown as a formula I,
wherein R and R' are each independently selected from the group consisting of-H, -CH 3 、
Or (b)
R' is C 11‑17 Straight chain alkyl of (a). The hydrate inhibitor can effectively inhibit the aggregation of hydrate particles and the adhesion of the hydrate particles on the pipe wall, thereby preventing the blockage of a shaft, greatly reducing the dosage of the traditional hydrate inhibitor, reducing the operation cost and the safety risk, and providing technical support for the drilling and the development of ocean deepwater oil gas and natural gas hydrates.
Description
Technical Field
The invention relates to the technical field of petrochemical industry, in particular to a hydrate inhibitor and a preparation method and application thereof.
Background
Natural gas hydrates are ice-like crystalline substances produced from water and natural gas under conditions of low temperature and high pressure. In the deep sea oil gas and natural gas hydrate drilling and production process, the temperature of the sea water and the stratum is low, and the hydrostatic pressure is high, so that good conditions are provided for the generation of the natural gas hydrate. Under the low-temperature high-pressure condition in the drilling and production process, hydrate particles are generated, gathered, adhered to the pipe wall and block the shaft, so that the shaft flow is blocked, and the normal running of drilling and completion, testing and hydrate production operations are affected.
At present, in the drilling and production of sea deepwater oil gas and natural gas hydrate, a method for inhibiting hydrate generation by using a large amount of hydrate thermodynamic inhibitors is mainly adopted to control shaft flow disorders, including methanol, ethylene glycol, sodium chloride and the like. Thermodynamic inhibitors prevent the formation of hydrates by changing the phase equilibrium conditions of hydrate formation, i.e., changing the temperature and pressure conditions under which the hydrate is formed. However, the existing problems are that the consumption of the inorganic salt is large, the consumption is usually more than 10 percent, and the cost is high, even more than 50 percent, of the mass of the water phase, the marine environment is polluted, and the equipment corrosion problem can be caused by the high concentration of the inorganic salt. The offshore operation platform has limited space, and the transportation and storage of a large amount of hydrate thermodynamic inhibitors increase logistical support burden and have potential safety hazards.
Aiming at a plurality of problems existing in the currently applied hydrate thermodynamic inhibitors, the research on low-dose inhibitors is started at home and abroad, and the low-dose inhibitors are hoped to replace the thermodynamic inhibitors, and mainly comprise hydrate kinetic inhibitors and anti-agglomerants, including PVP, PVCap, VP/VC and the like. However, studies and practices show that kinetic inhibitors are very harsh in use and essentially fail at high supercooling temperatures. In the drilling and production process of ocean deepwater oil gas and natural gas hydrate, the low-temperature high-pressure environment on the sea bottom creates a high-supercooling condition, and the hydrate is extremely easy to gather and cause shaft blockage. Under such wellbore conditions, kinetic inhibitors fail to provide the desired hydrate formation inhibition effect and thus there remains a need to rely on high concentrations of thermodynamic inhibitors for control.
Thus, current sea deepwater natural gas hydrate drilling and deepwater oil and gas production still rely on the addition of large amounts of thermodynamic inhibitors to control hydrate flow disorders. Studies have shown that agglomeration among natural gas hydrate particles and adhesion deposition on the wall surface of the tube are key causes of hydrate blockage. Small amounts of hydrate particles are formed in the wellbore and the pipeline and if no agglomeration between particles occurs, they remain dispersed, causing no blockage.
Disclosure of Invention
The invention aims to solve the problem of hydrate blockage of a drilling and production shaft of marine deep water oil gas and natural gas hydrate in the prior art, and provides a hydrate inhibitor and a preparation method and application thereof. The hydrate inhibitor can effectively inhibit the aggregation of hydrate particles and the adhesion of the hydrate particles on the pipe wall, thereby preventing the blockage of a shaft, greatly reducing the dosage of the traditional hydrate inhibitor, reducing the operation cost and the safety risk, and providing technical support for the drilling and development of ocean deepwater oil gas and natural gas hydrates.
In order to achieve the above object, the first aspect of the present invention provides a hydrate inhibitor represented by formula i,
wherein R and R' are each independently selected from the group consisting of-H, -CH 3 、
The second aspect of the invention provides a method for preparing the hydrate inhibitor, which comprises the following steps:
in the presence of a catalyst, a monomer containing carboxyl and a small molecular amino compound react to obtain the hydrate inhibitor.
The third aspect of the invention provides an application of the hydrate inhibitor provided by the invention or the hydrate inhibitor prepared by the method provided by the invention in hydrate exploitation.
The fourth aspect of the invention provides a hydrate inhibitor provided by the invention or a drilling fluid of the hydrate inhibitor prepared by the method provided by the invention.
Through the technical scheme, when the hydrate inhibitor is used in drilling fluid for hydrate exploitation, the cohesion among the natural gas hydrate particles and the adhesion between the hydrate particles and the wall surface of a shaft can be effectively reduced, the purpose of inhibiting the aggregation of the hydrate particles and the blockage of the shaft can be achieved, and the hydrate inhibitor can be applied to deep sea oil gas and natural gas hydrate exploitation.
Detailed Description
The endpoints and any values of the ranges disclosed herein are not limited to the precise range or value, and are understood to encompass values approaching those ranges or values. For numerical ranges, one or more new numerical ranges may be found between the endpoints of each range, between the endpoint of each range and the individual point value, and between the individual point value, in combination with each other, and are to be considered as specifically disclosed herein.
In a first aspect the present invention provides a hydrate inhibitor of formula i,
wherein R and R' are each independently selected from the group consisting of-H, -CH 3 、
According to the hydrate inhibitor provided by the invention, alkyl, amino and amide groups are introduced, on one hand, the amide groups can be adsorbed on the surfaces of natural gas hydrate particles, so that the growth of the natural gas hydrate particles is inhibited; on the other hand, alkyl extends to the periphery on the surface of the hydrate particles, and a layer of coating is formed on the surface of the hydrate particles, so that the wettability of the surface of the natural gas hydrate is changed, the steric hindrance among the natural gas hydrate particles is increased, and meanwhile, the adhesion between the natural gas hydrate particles and the surface of the hydrophilic pipe wall is reduced. The double-effect inhibitor has good functions of inhibiting the aggregation and adhesion of natural gas hydrate particles on the wall surface of the pipe wall, and can effectively prevent the aggregation and adhesion of the natural gas hydrate particles in the deep sea oil gas and hydrate drilling well shaft, thereby avoiding the blocking of the well shaft.
When the hydrate inhibitor is used for exploiting natural gas hydrate in drilling fluid, the hydrate inhibitor can effectively inhibit hydrate aggregation and adhesion to the pipe wall when the concentration of the hydrate inhibitor in the drilling fluid is low (less than or equal to 1 wt%) so as to prevent a well bore from being blocked; compared with the thermodynamic method of using sodium chloride and glycol which are hydrate thermodynamic inhibitors with the concentration of 10-50% in the traditional drilling fluid, the addition amount of the hydrate inhibitor in the drilling fluid is greatly reduced, so that the operation cost and the environmental hazard are effectively reduced.
According to the invention, R and R' are preferably each independently selected from-H and/or
In a preferred embodiment of the present invention, preferably, the hydrate inhibitor is selected from one of the following hydrate inhibitor combinations:
hydrate inhibitor-1: r is-H, R' is
R' is C 11 A linear alkyl group of (a);
hydrate inhibitor-2: r is-H, R' is
R' is C 15 A linear alkyl group of (a);
hydrate inhibitor-3: r is-H, R' is
R' is C 17 Straight chain alkyl of (a).
The second aspect of the invention provides a method for preparing the hydrate inhibitor, which comprises the following steps:
in the presence of a catalyst, a monomer containing carboxyl and a small molecular amino compound react to obtain the hydrate inhibitor.
In a preferred embodiment of the present invention, preferably, the weight ratio of the carboxyl group-containing monomer to the small molecule amino compound is 4-5:2-4.
In a preferred embodiment of the present invention, preferably, the carboxyl group-containing monomer is selected from one or more of lauric acid, myristic acid, palmitic acid, stearic acid.
In a preferred embodiment of the present invention, preferably, the small molecule amino compound is selected from one or more of N-methyl-2, 2-diaminodiethylamine, 3-dimethylaminopropylamine, N- (3-dimethylaminopropyl) methacrylamide, 3-methylaminopropylamine, N-dimethylethylenediamine, ethylenediamine.
In a preferred embodiment of the present invention, the reaction temperature is preferably 60 to 95℃and the reaction time is preferably 1.5 to 3.5 hours.
In a preferred embodiment of the invention, the catalyst is preferably selected from sodium methoxide and/or N, N-carbonyldiimidazole.
In a preferred embodiment of the present invention, the catalyst is preferably used in an amount of 0.5 to 2wt% of the carboxyl group-containing monomer.
The third aspect of the invention provides an application of the hydrate inhibitor provided by the invention or the hydrate inhibitor prepared by the method provided by the invention in hydrate exploitation.
The fourth aspect of the invention provides a hydrate inhibitor provided by the invention or a drilling fluid of the hydrate inhibitor prepared by the method provided by the invention.
In a preferred embodiment of the present invention, preferably, the hydrate inhibitor is contained in an amount of 0.1 to 1wt%.
The composition of the drilling fluid may include: a base fluid and the hydrate inhibitor. The composition of the base liquid may be of a composition known in the art. Preferably, in the present invention, a typical base liquid formulation may be employed comprising the following components in parts by weight: 1-8 parts of seawater bentonite slurry, 0.1-0.5 part of alkaline regulator, 0.1-0.8 part of tackifier, 0.3-3 parts of filtrate reducer, 0.3-18 parts of inhibitor and 1-3 parts of lubricant, wherein the hydrate inhibitor is 0.1-1 part.
In a preferred embodiment of the present invention, preferably, the alkaline regulator is NaOH, the tackifier is polyanionic cellulose (PAC-LV) and/or xanthan gum (XC), the fluid loss additive is JLS-2, the inhibitor is at least one of SDJA, sodium chloride and potassium chloride, and the lubricant is PF-LUBE. Wherein, the JLS-2 is polymerized by a temperature-resistant and salt-resistant monomer (AMPS), acrylamide (AM), a cationic monomer dimethyl diallyl ammonium chloride (DMDAAC) and an ester monomer (BXZ) with a hydrophobic effect, and the specific disclosure of the oil field chemistry 2012, volume 29, phase 2, p.129-132 (full red, etc.) can be seen.
The SDJA is obtained by polymerizing polyether diamine and ethylene oxide, and can be concretely found in disclosure of oil drilling technology 2013 (041) 003, p.35-39 (Guo Gang, etc.).
The PF-LUBE is a conventional lubricant and is obtained by reacting vegetable oil and/or mineral oil with other surfactants.
The drilling fluid containing the hydrate inhibitor provided by the invention has positive effects on well wall stabilization in the drilling process when natural gas hydrate is produced, and improves the safety of drilling operation.
The present invention will be described in detail by examples. In the following examples, the rheological parameters and API fluid loss of drilling fluids were tested by national standard "GB/T29170-2012 laboratory test for drilling fluids in the oil and gas industry".
Evaluation of effects of inhibiting aggregation of hydrate and adhesion to wall of pipe
In the evaluation of the effect of the hydrate inhibitor on aggregation and adhesion to the pipe wall, an analysis method combining macroscopic evaluation and microscopic experiment is adopted:
on a macroscopic scale, the inhibition effect of the embodiment of the invention on the blocking of the hydrate is evaluated by using a natural gas hydrate inhibition evaluation experimental device of China Petroleum university (Huadong). The experimental device consists of a high-pressure reaction kettle, a constant-temperature water bath, a booster pump, a magnetic stirring system, a vacuum pump, a gas flowmeter, a temperature sensor, a pressure sensor, a torque sensor and a data acquisition system. In the experimental process, the temperature, pressure and torque in the reaction kettle are monitored and recorded in real time by a data acquisition system. The experimental gas is methane gas. In the experimental process, when a small amount of hydrate particles are generated in the reaction kettle, but the particles are in a dispersed state, the particles are not blocked, the torque value monitored in real time is slightly increased, and the state can be kept stable. When a large amount of hydrate is generated and aggregation occurs, stirring resistance is increased, and torque is greatly increased; when a hydrate is formed in the reaction kettle to block, the torque value reaches a peak value, and stirring cannot be continued. Therefore, the hydrate inhibitor has an important effect of inhibiting the blocking of the hydrate by analyzing the change law of the torque with time. The experimental temperature is 4 ℃, the pressure is 15MPa, and the water depth condition of 1500m is simulated. The stirring rate was 200r/min, simulating wellbore fluid flow conditions. The experimental time is 10 hours, and hydrate blockage is formed in 10 hours, which indicates that the inhibitor can not effectively prevent and treat hydrate flow disorder; if no blockage is formed for more than 10 hours, stirring can still be performed normally, and the inhibitor can be considered to be capable of effectively preventing and controlling the blockage of hydrate within a safe operation time window, so that the wellbore fluid can be ensured to safely return to the ground from the bottom of the well.
On a microscopic scale, the effect of inhibiting hydrate aggregation and adhering to a pipe wall is evaluated by adopting a natural gas inter-particle surrounding force experimental device of China Petroleum university (Huadong). The hydrate particle interaction force tester takes a Leica S-APO type microscope as a core, and is mainly used for testing microscopic interaction force among hydrate particles. The device consists of three main parts of a microscopic imaging system, a microscopic control system and a temperature control system. Observing the state of the hydrate particles through a microscopic imaging device, and displaying the state at a computer end; the micro-manipulation system may move the hydrate particles to make measurements; the temperature of the hydrate particle environment in the reaction kettle is controlled by the constant temperature control system, and the temperature in an actual shaft is simulated. The microscopic acting force among particles is one of key factors for determining whether the hydrate particles are aggregated and adhered to a pipe wall, and the measurement of the acting force among the hydrate particles under the action of different inhibitors is of great importance for evaluating the aggregation of the hydrate particles in a shaft. Methane hydrate formed in a submarine low-temperature high-pressure environment has the same structure as cyclopentane hydrate formed in a normal pressure at 2 ℃, so that the cyclopentane hydrate is selected to study acting force among hydrate particles.
Example 1
(1) 100g of lauric acid and 46g of 3-dimethylaminopropylamine are weighed and slowly added into a closed three-neck flask with a reflux condenser, and then 0.5g of sodium methoxide is added;
(2) Heating the reactant to 80 ℃ under stirring, and refluxing for 2 hours to complete the reaction;
(3) Cooling the three-neck flask to room temperature, heating the reaction system to 30 ℃ and removing unreacted 3-dimethylaminopropylamine by adopting a reduced pressure distillation method to obtain a compound A1 containing byproducts;
(4) And finally, adding the natural gas hydrate double-effect inhibitor containing the byproducts into water with the volume of 2-3 times, stirring, heating to 50 ℃, distilling under reduced pressure until no distillate appears, and repeating for 3 times to obtain the compound A1 without the byproducts.
The compound is proved to contain alkyl, amino and amide groups by infrared detection, and is analyzed to have a structure shown as a formula (1), wherein R is-H, and R' is
R' is C 11 Straight chain alkyl of (a).
Example 2
(1) Weighing 100g of stearic acid and 46g of 3-dimethylaminopropylamine, slowly adding the mixture into a closed three-neck flask with a reflux condenser, and then adding 0.5g of sodium methoxide;
(2) Heating the reactant to 60 ℃ under stirring, and refluxing for 2 hours to complete the reaction;
(3) Cooling the three-neck flask to room temperature, heating the reaction system to 30 ℃, and removing unreacted 3-dimethylaminopropylamine by adopting a reduced pressure distillation method to obtain a compound A2 containing byproducts;
(4) And finally, adding the natural gas hydrate double-effect inhibitor containing the byproducts into water with the volume of 2-3 times, stirring, heating to 50 ℃, distilling under reduced pressure until no distillate appears, and repeating for 3 times to obtain the compound A2 without the byproducts.
The assay was performed as in example 1, with the structure of compound A2 wherein R is-H and R' is
R' is C 17 Straight chain alkyl of (a).
Example 3
(1) 100g of palmitic acid and 46g of 3-dimethylaminopropylamine are weighed and slowly added into a closed three-neck flask with a reflux condenser, and then 0.5g of sodium methoxide is added;
(2) Heating the reactant to 80 ℃ under stirring, and refluxing for 2 hours to complete the reaction;
(3) Cooling the three-neck flask to room temperature, heating the reaction system to 30 ℃, and removing unreacted 3-dimethylaminopropylamine by adopting a reduced pressure distillation method to obtain a compound A3 containing byproducts;
(4) And finally, adding the natural gas hydrate double-effect inhibitor containing the byproducts into water with the volume of 2-3 times, stirring, heating to 50 ℃, distilling under reduced pressure until no distillate appears, and repeating for 3 times to obtain the compound A3 without the byproducts.
The assay was performed as in example 1, with the structure of compound A3, wherein R is-H and R' is
R' is C 15 Straight chain alkyl of (a).
Example 4
(1) 128g of palmitic acid and 51g of 3-methylaminopropylamine are weighed and slowly added into a closed three-neck flask with a reflux condenser, and then 0.5g of sodium methoxide is added;
(2) Heating the reactant to 80 ℃ under stirring, and refluxing for 2 hours to complete the reaction;
(3) Cooling the three-neck flask to room temperature, heating the reaction system to 30 ℃ and removing unreacted 3-methylaminopropylamine by adopting a reduced pressure distillation method to obtain a compound A4 containing byproducts;
(4) And finally, adding the natural gas hydrate double-effect inhibitor containing the byproducts into water with the volume of 2-3 times, stirring, heating to 50 ℃, distilling under reduced pressure until no distillate appears, and repeating for 3 times to obtain the compound A4 without the byproducts.
The assay was performed as in example 1, with the structure of compound A4, wherein R is-H and R' is
R' is C 15 Straight chain alkyl of (a).
Test case
Test for inhibiting aggregation and adhesion of hydrate particles on pipe wall
The compounds A1 to 4 prepared in examples 1 to 4 were each prepared as an aqueous solution having a mass concentration of 0.5%, and stirred uniformly. And (3) respectively dipping a drop of solution to be tested on the glass fiber by a dropping dipping method, placing the glass fiber in liquid nitrogen for quenching for 1min, quickly placing the glass fiber into a reaction container filled with cyclopentane at the temperature of-2 ℃ after the glass fiber is completely converted into ice particles, and standing for 3min. After the surface layer of the ice particles is converted into cyclopentane hydrate particles, the temperature of a reaction vessel is raised to 2 ℃, the reaction vessel is kept stand for 30min, and after the ice particles are completely converted into cyclopentane hydrate particles, the cohesion between the hydrate particles is measured by a pull-off method; after the measurement is completed, one cyclopentane hydrate particle is replaced by a metal sheet which is the same as the material of the shaft, and the adhesion force between the cyclopentane hydrate particle and the wall surface of the shaft is measured. The same measurement was carried out with clean water instead, and the results are shown in table 1.
In order to evaluate the compatibility of the inhibitor and the drilling fluid, a typical deep water drilling fluid formula is adopted as base slurry, and the formula is as follows: seawater bentonite slurry 3 parts, naOH 0.2 parts, na 2 CO 3 0.15 part, PAC-LV 0.5 part, JLS-2.5 parts, XC 0.3 part, SDJA 1 part, sodium chloride 10 parts, potassium chloride 5 parts and PF-LUBE1.5 parts.
Testing base slurry and rheological property and fluid loss property of drilling fluid respectively obtained after the compounds A1-4 prepared by the invention are respectively added into the base slurry, and analyzing whether the addition of an inhibitor can negatively affect the performance of the drilling fluid. The results are shown in Table 2.
TABLE 1
TABLE 2
| AV/(mPa·s) | PV/(mPa·s) | YP/(Pa) | API fluid loss/(mL) | |
| Example 1 | 82 | 60 | 20 | 1.8 |
| Example 2 | 78 | 57 | 22 | 1.5 |
| Example 3 | 76 | 55 | 20 | 1.6 |
| Example 4 | 75 | 58 | 19 | 1.6 |
| Base slurry | 69 | 53 | 16 | 2.0 |
The results in table 1 show that the hydrate inhibitor can effectively reduce the cohesion between natural gas hydrate particles and the adhesion between the hydrate particles and the wall surface of a shaft, and achieve the purposes of inhibiting the aggregation of the hydrate particles and inhibiting the blockage of the shaft.
The results in table 2 show that the viscosity of the drilling fluid containing the hydrate inhibitor provided by the invention is increased, the fluid loss is reduced, and the compatibility of the drilling fluid with the drilling fluid is good, so that the drilling fluid can be applied to drilling operation.
The preferred embodiments of the present invention have been described in detail above, but the present invention is not limited thereto. Within the scope of the technical idea of the invention, a number of simple variants of the technical solution of the invention are possible, including combinations of the individual technical features in any other suitable way, which simple variants and combinations should likewise be regarded as being disclosed by the invention, all falling within the scope of protection of the invention.
Claims (11)
1. A hydrate inhibitor is shown in formula I,
wherein R and R' are each independently selected from the group consisting of,
2. The hydrate inhibitor according to claim 1, wherein R and R' are each independently selected from and/or
3. The hydrate inhibitor according to claim 1 or 2, wherein the hydrate inhibitor is selected from one of the following hydrate inhibitor combinations:
hydrate inhibitor-1: r is R' is
R' is C 11 A linear alkyl group of (a);
hydrate inhibitor-2: r is R' is
R' is C 15 A linear alkyl group of (a);
hydrate inhibitor-3: r is R' is
R' is C 17 Straight chain alkyl of (a).
4. A method of preparing a hydrate inhibitor comprising the steps of:
in the presence of a catalyst, a monomer containing carboxyl and a small molecular amino compound react to obtain the hydrate inhibitor.
5. The method of claim 4, wherein the weight ratio of the carboxyl group-containing monomer to the small molecule amino compound is 4-5:2-4.
6. The method according to claim 4 or 5, wherein the carboxyl group-containing monomer is selected from one or more of lauric acid, myristic acid, palmitic acid, stearic acid.
7. The method of any of claims 4-6, wherein the small molecule amino compound is selected from one or more of N-methyl-2, 2-diaminodiethylamine, 3-dimethylaminopropylamine, N- (3-dimethylaminopropyl) methacrylamide, 3-methylaminopropylamine, N-dimethylethylenediamine, ethylenediamine.
8. The process according to any one of claims 4 to 7, wherein the reaction temperature is 60 to 95 ℃ and the reaction time is 1.5 to 3.5 hours.
9. A process according to any one of claims 4 to 8, wherein the catalyst is selected from sodium methoxide and/or N, N-carbonyldiimidazole;
preferably, the catalyst is used in an amount of 0.5 to 2wt% of the carboxyl group-containing monomer.
10. Use of a hydrate inhibitor according to any one of claims 1 to 3 or a hydrate inhibitor obtainable by a method according to any one of claims 4 to 9 in hydrate drilling and production.
11. A drilling fluid comprising the hydrate inhibitor of any one of claims 1-3 or the hydrate inhibitor produced by the method of any one of claims 4-9;
preferably, the content of the hydrate inhibitor in the drilling fluid is 0.1-1wt%.
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