CN116836691A - Water-based drilling fluid system for hydrate stratum and preparation method and application thereof - Google Patents
Water-based drilling fluid system for hydrate stratum and preparation method and application thereof Download PDFInfo
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- CN116836691A CN116836691A CN202210307586.0A CN202210307586A CN116836691A CN 116836691 A CN116836691 A CN 116836691A CN 202210307586 A CN202210307586 A CN 202210307586A CN 116836691 A CN116836691 A CN 116836691A
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- hydrate
- drilling fluid
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- inhibitor
- fluid system
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- 238000005553 drilling Methods 0.000 title claims abstract description 108
- 239000012530 fluid Substances 0.000 title claims abstract description 98
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 49
- 238000002360 preparation method Methods 0.000 title abstract description 7
- 239000003112 inhibitor Substances 0.000 claims abstract description 62
- LYCAIKOWRPUZTN-UHFFFAOYSA-N Ethylene glycol Chemical compound OCCO LYCAIKOWRPUZTN-UHFFFAOYSA-N 0.000 claims abstract description 36
- 239000003638 chemical reducing agent Substances 0.000 claims abstract description 33
- 239000000706 filtrate Substances 0.000 claims abstract description 33
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 claims abstract description 30
- 238000000354 decomposition reaction Methods 0.000 claims abstract description 30
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 claims abstract description 24
- 239000011734 sodium Substances 0.000 claims abstract description 23
- 229910052708 sodium Inorganic materials 0.000 claims abstract description 23
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 claims abstract description 22
- 239000002002 slurry Substances 0.000 claims abstract description 20
- 239000002689 soil Substances 0.000 claims abstract description 20
- 239000011780 sodium chloride Substances 0.000 claims abstract description 15
- IIZPXYDJLKNOIY-JXPKJXOSSA-N 1-palmitoyl-2-arachidonoyl-sn-glycero-3-phosphocholine Chemical compound CCCCCCCCCCCCCCCC(=O)OC[C@H](COP([O-])(=O)OCC[N+](C)(C)C)OC(=O)CCC\C=C/C\C=C/C\C=C/C\C=C/CCCCC IIZPXYDJLKNOIY-JXPKJXOSSA-N 0.000 claims abstract description 12
- 239000000787 lecithin Substances 0.000 claims abstract description 12
- 235000010445 lecithin Nutrition 0.000 claims abstract description 12
- 229940067606 lecithin Drugs 0.000 claims abstract description 12
- 239000001103 potassium chloride Substances 0.000 claims abstract description 12
- 235000011164 potassium chloride Nutrition 0.000 claims abstract description 12
- 229920000036 polyvinylpyrrolidone Polymers 0.000 claims abstract description 4
- 239000001267 polyvinylpyrrolidone Substances 0.000 claims abstract description 4
- 235000013855 polyvinylpyrrolidone Nutrition 0.000 claims abstract description 4
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 claims description 36
- CDBYLPFSWZWCQE-UHFFFAOYSA-L Sodium Carbonate Chemical compound [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 claims description 24
- 230000015572 biosynthetic process Effects 0.000 claims description 22
- 239000000314 lubricant Substances 0.000 claims description 19
- 229910000029 sodium carbonate Inorganic materials 0.000 claims description 12
- 229920002401 polyacrylamide Polymers 0.000 claims description 7
- 229920002134 Carboxymethyl cellulose Polymers 0.000 claims description 6
- 239000000440 bentonite Substances 0.000 claims description 5
- 229910000278 bentonite Inorganic materials 0.000 claims description 5
- SVPXDRXYRYOSEX-UHFFFAOYSA-N bentoquatam Chemical compound O.O=[Si]=O.O=[Al]O[Al]=O SVPXDRXYRYOSEX-UHFFFAOYSA-N 0.000 claims description 5
- 238000000034 method Methods 0.000 claims description 5
- 239000003002 pH adjusting agent Substances 0.000 claims description 5
- 229920002472 Starch Polymers 0.000 claims description 4
- 239000000654 additive Substances 0.000 claims description 4
- 230000000996 additive effect Effects 0.000 claims description 4
- 229920000768 polyamine Polymers 0.000 claims description 4
- 239000008107 starch Substances 0.000 claims description 4
- 235000019698 starch Nutrition 0.000 claims description 4
- BTMZHHCFEOXAAN-UHFFFAOYSA-N 2-[bis(2-hydroxyethyl)amino]ethanol;2-dodecylbenzenesulfonic acid Chemical compound OCCN(CCO)CCO.CCCCCCCCCCCCC1=CC=CC=C1S(O)(=O)=O BTMZHHCFEOXAAN-UHFFFAOYSA-N 0.000 claims description 3
- KXGFMDJXCMQABM-UHFFFAOYSA-N 2-methoxy-6-methylphenol Chemical class [CH]OC1=CC=CC([CH])=C1O KXGFMDJXCMQABM-UHFFFAOYSA-N 0.000 claims description 3
- 239000001768 carboxy methyl cellulose Substances 0.000 claims description 3
- 235000010948 carboxy methyl cellulose Nutrition 0.000 claims description 3
- 125000002057 carboxymethyl group Chemical group [H]OC(=O)C([H])([H])[*] 0.000 claims description 3
- 239000008112 carboxymethyl-cellulose Substances 0.000 claims description 3
- 239000004519 grease Substances 0.000 claims description 3
- 239000003077 lignite Substances 0.000 claims description 3
- 229920001515 polyalkylene glycol Polymers 0.000 claims description 3
- 229920005614 potassium polyacrylate Polymers 0.000 claims description 3
- 239000011347 resin Substances 0.000 claims description 3
- 229920005989 resin Polymers 0.000 claims description 3
- 230000015556 catabolic process Effects 0.000 claims description 2
- 229920013818 hydroxypropyl guar gum Polymers 0.000 claims description 2
- XAEFZNCEHLXOMS-UHFFFAOYSA-M potassium benzoate Chemical compound [K+].[O-]C(=O)C1=CC=CC=C1 XAEFZNCEHLXOMS-UHFFFAOYSA-M 0.000 claims description 2
- 239000002131 composite material Substances 0.000 claims 2
- MQRJBSHKWOFOGF-UHFFFAOYSA-L disodium;carbonate;hydrate Chemical compound O.[Na+].[Na+].[O-]C([O-])=O MQRJBSHKWOFOGF-UHFFFAOYSA-L 0.000 claims 1
- NLYAJNPCOHFWQQ-UHFFFAOYSA-N kaolin Chemical compound O.O.O=[Al]O[Si](=O)O[Si](=O)O[Al]=O NLYAJNPCOHFWQQ-UHFFFAOYSA-N 0.000 claims 1
- 230000005764 inhibitory process Effects 0.000 abstract description 13
- 230000036571 hydration Effects 0.000 abstract description 9
- 238000006703 hydration reaction Methods 0.000 abstract description 9
- 230000008929 regeneration Effects 0.000 abstract 1
- 238000011069 regeneration method Methods 0.000 abstract 1
- 239000007789 gas Substances 0.000 description 21
- 102100021913 Sperm-associated antigen 8 Human genes 0.000 description 11
- 101710098579 Sperm-associated antigen 8 Proteins 0.000 description 11
- 238000012360 testing method Methods 0.000 description 10
- 230000008859 change Effects 0.000 description 9
- 230000000052 comparative effect Effects 0.000 description 8
- 239000011435 rock Substances 0.000 description 8
- 229920003082 Povidone K 90 Polymers 0.000 description 7
- 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 7
- 238000002474 experimental method Methods 0.000 description 6
- 239000010426 asphalt Substances 0.000 description 4
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 4
- 238000011084 recovery Methods 0.000 description 4
- 229940092782 bentonite Drugs 0.000 description 3
- 238000006243 chemical reaction Methods 0.000 description 3
- 239000003795 chemical substances by application Substances 0.000 description 3
- 239000004927 clay Substances 0.000 description 3
- WGCNASOHLSPBMP-UHFFFAOYSA-N hydroxyacetaldehyde Natural products OCC=O WGCNASOHLSPBMP-UHFFFAOYSA-N 0.000 description 3
- 239000003921 oil Substances 0.000 description 3
- 239000007787 solid Substances 0.000 description 3
- 230000009286 beneficial effect Effects 0.000 description 2
- 150000001875 compounds Chemical class 0.000 description 2
- 238000005520 cutting process Methods 0.000 description 2
- 239000006185 dispersion Substances 0.000 description 2
- 238000011156 evaluation Methods 0.000 description 2
- 239000000203 mixture Substances 0.000 description 2
- 239000003345 natural gas Substances 0.000 description 2
- 238000011056 performance test Methods 0.000 description 2
- 150000003839 salts Chemical class 0.000 description 2
- 239000013535 sea water Substances 0.000 description 2
- 239000013049 sediment Substances 0.000 description 2
- 239000000126 substance Substances 0.000 description 2
- NWUYHJFMYQTDRP-UHFFFAOYSA-N 1,2-bis(ethenyl)benzene;1-ethenyl-2-ethylbenzene;styrene Chemical compound C=CC1=CC=CC=C1.CCC1=CC=CC=C1C=C.C=CC1=CC=CC=C1C=C NWUYHJFMYQTDRP-UHFFFAOYSA-N 0.000 description 1
- QJZYHAIUNVAGQP-UHFFFAOYSA-N 3-nitrobicyclo[2.2.1]hept-5-ene-2,3-dicarboxylic acid Chemical compound C1C2C=CC1C(C(=O)O)C2(C(O)=O)[N+]([O-])=O QJZYHAIUNVAGQP-UHFFFAOYSA-N 0.000 description 1
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 1
- 239000002318 adhesion promoter Substances 0.000 description 1
- 239000003729 cation exchange resin Substances 0.000 description 1
- 125000002091 cationic group Chemical group 0.000 description 1
- 238000004140 cleaning Methods 0.000 description 1
- 239000011248 coating agent Substances 0.000 description 1
- 238000000576 coating method Methods 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 239000013078 crystal Substances 0.000 description 1
- 230000003111 delayed effect Effects 0.000 description 1
- ONCZQWJXONKSMM-UHFFFAOYSA-N dialuminum;disodium;oxygen(2-);silicon(4+);hydrate Chemical compound O.[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[O-2].[Na+].[Na+].[Al+3].[Al+3].[Si+4].[Si+4].[Si+4].[Si+4] ONCZQWJXONKSMM-UHFFFAOYSA-N 0.000 description 1
- 238000010494 dissociation reaction Methods 0.000 description 1
- 230000005593 dissociations Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- 239000012634 fragment Substances 0.000 description 1
- 150000004676 glycans Chemical class 0.000 description 1
- PCHJSUWPFVWCPO-UHFFFAOYSA-N gold Chemical compound [Au] PCHJSUWPFVWCPO-UHFFFAOYSA-N 0.000 description 1
- 239000010931 gold Substances 0.000 description 1
- 229910052737 gold Inorganic materials 0.000 description 1
- 239000004021 humic acid Substances 0.000 description 1
- -1 hydroxypropyl Chemical group 0.000 description 1
- 230000002401 inhibitory effect Effects 0.000 description 1
- 229910017053 inorganic salt Inorganic materials 0.000 description 1
- 230000003993 interaction Effects 0.000 description 1
- 239000010687 lubricating oil Substances 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 231100000956 nontoxicity Toxicity 0.000 description 1
- 239000002245 particle Substances 0.000 description 1
- 239000003208 petroleum Substances 0.000 description 1
- 229920000642 polymer Polymers 0.000 description 1
- 229920001282 polysaccharide Polymers 0.000 description 1
- 239000005017 polysaccharide Substances 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 150000003242 quaternary ammonium salts Chemical class 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000000518 rheometry Methods 0.000 description 1
- 238000005096 rolling process Methods 0.000 description 1
- 229940080314 sodium bentonite Drugs 0.000 description 1
- 229910000280 sodium bentonite Inorganic materials 0.000 description 1
- 239000007790 solid phase Substances 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 239000004575 stone Substances 0.000 description 1
- 238000003860 storage Methods 0.000 description 1
- 125000001273 sulfonato group Chemical group [O-]S(*)(=O)=O 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 230000002195 synergetic effect Effects 0.000 description 1
- 229940105956 tea-dodecylbenzenesulfonate Drugs 0.000 description 1
- 238000010998 test method Methods 0.000 description 1
- 239000012085 test solution Substances 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
- C09K8/04—Aqueous well-drilling compositions
- C09K8/14—Clay-containing compositions
- C09K8/18—Clay-containing compositions characterised by the organic compounds
- C09K8/22—Synthetic organic compounds
- C09K8/24—Polymers
-
- 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
- C09K8/04—Aqueous well-drilling compositions
- C09K8/14—Clay-containing compositions
- C09K8/18—Clay-containing compositions characterised by the organic compounds
- C09K8/20—Natural organic compounds or derivatives thereof, e.g. polysaccharides or lignin derivatives
- C09K8/206—Derivatives of other natural products, e.g. cellulose, starch, sugars
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/5083—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained by reactions only involving carbon-to-carbon unsaturated bonds
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/5086—Compositions based on water or polar solvents containing organic compounds macromolecular compounds obtained otherwise than by reactions only involving carbon-to-carbon unsaturated bonds
-
- 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/506—Compositions based on water or polar solvents containing organic compounds
- C09K8/508—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/514—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
-
- 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
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/524—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning organic depositions, e.g. paraffins or asphaltenes
-
- 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
- C09K2208/12—Swell inhibition, i.e. using additives to drilling or well treatment fluids for inhibiting clay or shale swelling or disintegrating
-
- 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
-
- 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
- C09K2208/34—Lubricant additives
Abstract
The invention relates to the field of drilling fluid, and discloses a water-based drilling fluid system for a hydrate stratum, and a preparation method and application thereof. The water-based drilling fluid system for the hydrate stratum comprises sodium soil slurry, a tackifier, a filtrate reducer, a hydrate thermodynamic inhibitor and a hydrate decomposition inhibitor; wherein the hydrate thermodynamic inhibitor is selected from one or more of ethylene glycol, sodium chloride and potassium chloride; the hydrate decomposition inhibitor is selected from one or more of lecithin and polyvinylpyrrolidone. The water-based drilling fluid system has good low-temperature rheological property, fluid loss property and hydration inhibition property, can effectively inhibit the decomposition of hydrate at the bottom of a hydrate stratum and the regeneration of the hydrate in a shaft, and can be applied to the drilling of the hydrate stratum.
Description
Technical Field
The invention relates to the technical field of drilling fluid, in particular to a water-based drilling fluid system for a hydrate stratum, and a preparation method and application thereof.
Background
Compared with conventional land and marine drilling, a series of special problems such as hydrate blockage, marine engineering accidents and the like can be faced in the drilling process of a natural gas hydrate stratum. In marine deep water drilling engineering, the formation of natural gas hydrate in a well bore or the decomposition of hydrate in a sedimentary stratum is one of the important reasons for causing underground accidents, and the hazards mainly comprise two types: (1) Once the seabed shallow gas-containing high-pressure stratum is uncovered, once the gas enters the water-based drilling fluid, solid hydrate is easy to form under proper conditions, a shaft and a blowout preventer are blocked, the drilling operation period is delayed, and even safety accidents are caused. (2) When the stratum of the natural gas hydrate is drilled, the stress of the well wall and the well bottom can be released, so that the effective stress of the stratum is reduced; the drill bit cuts broken rock, friction between the bottom hole and the rock core can generate a large amount of heat, and the condition that hydrate exists stably in the submarine sediment stratum is that a low-temperature high-pressure environment is maintained, if the temperature of drilling fluid is controlled improperly, the drilling fluid invades the hydrate stratum and exchanges heat with the hydrate stratum, and the hydrate is induced to be decomposed. The hydrate is decomposed to generate a large amount of gas and a small amount of water, so that the cementing strength of the sediment is reduced, when the solid hydrate plays a role in cementing or skeleton supporting, the hydrate is decomposed to cause the collapse of a well wall, the water content at the bottom of the well is increased by the water generated by the decomposition, the effective stress of cementing among stratum particles is reduced, the rock of the well wall is collapsed due to the fact that the cementing support is lost, and the instability of the well wall is aggravated; once the released gas enters a well bore, the performance of the drilling fluid is reduced, the capability of the drilling fluid for carrying rock fragments and purifying the well bore is affected, the density of the drilling fluid is reduced, the pressure of a drilling fluid column is reduced, the bottom hole pressure is reduced, and hydrate is further decomposed; in addition, the gas continues to circulate upwards along with the drilling fluid, so that equipment such as a drill rod and the like can be corroded, hydrate can be regenerated to block the drill rod, the subsea blowout preventer and the like when the seabed section meets proper temperature and pressure conditions, and the drilling fluid cannot normally circulate; the decomposition generates a large amount of gas to be suddenly released, which can cause kick and even blowout at the drilling platform, if a large amount of gas enters into seawater, the density of the seawater can be reduced, the buoyancy of the drilling platform is reduced and even lost, and the risk of the platform capsizing exists.
The patent with publication number of CN103146364B discloses a strong inhibition water-based drilling fluid, which consists of 100 parts of water, 0.2-4 parts of polyamine inhibitor, 0.1-1 part of coating inhibitor, 10-25 parts of hydrate inhibitor, 0.1-1 part of tackifier, 0.5-5 parts of filtrate reducer and 0.5-3 parts of liquid lubricant. The drilling fluid can inhibit the well wall instability of deep water shallow stratum, can solve the generation problem of hydrate in deep water drilling, and can be suitable for drilling operation with the water depth of 3000 m. The patent with publication number CN104531106A discloses an efficient hydrate inhibitory environment-friendly drilling fluid which consists of water, bentonite, quaternary ammonium salt type gemini surfactant, inorganic salt, sodium carboxymethyl starch, cationic polyacrylamide and solid anti-collapse lubricant GFRH, can be used for exploiting oil and gas resources on land or sea, effectively inhibits the generation of hydrate, has small harm to the environment by drilling fluid components, and has the advantages of high efficiency, environment friendliness and the like. The patent with publication number CN105018052A discloses a low solid phase low temperature polymer drilling fluid, which comprises a base fluid and a treating agent, wherein the base fluid is compounded by sodium bentonite and sodium chloride solution; the treating agent is sulfonate cation exchange resin and polysaccharide as flow regulator. The drilling fluid has strong decomposition inhibition performance under the low-temperature condition, good rheological property and low water loss. The drilling fluid has certain effects on natural gas hydrate storage and drilling, but the use of a compound hydrate inhibitor is not considered.
In view of the foregoing, it is desirable to provide a compound drilling fluid system that can improve the inhibition of hydrate formation and decomposition.
Disclosure of Invention
Aiming at the problems in the prior art, the invention provides a water-based drilling fluid system for a hydrate stratum, which has good compatibility among components, can be applied to the drilling of the hydrate stratum, and can inhibit the generation and decomposition of the hydrate. Also provides a preparation method and application of the water-based drilling fluid system.
The first aspect of the invention provides a water-based drilling fluid system for a hydrate stratum, which comprises sodium soil slurry, a tackifier, a filtrate reducer, a hydrate thermodynamic inhibitor and a hydrate decomposition inhibitor;
wherein the hydrate thermodynamic inhibitor is selected from one or more of ethylene glycol, sodium chloride and potassium chloride.
The hydrate decomposition inhibitor is selected from one or more of lecithin and polyvinylpyrrolidone.
According to some embodiments of the invention, shale inhibitors are also included.
According to some embodiments of the invention, the shale inhibitor is selected from one or more of a polyamine shale inhibitor, a sylvite humic shale inhibitor, and a bitumen shale inhibitor.
According to some embodiments of the invention, the fluid loss additive is selected from one or more of a sulfonated phenolic resin, a sulfonated lignite resin, and carboxymethyl starch.
According to some embodiments of the invention, the filtrate reducer is preferably one or two of filtrate reducer SD-102 and filtrate reducer JLS-1.
According to some embodiments of the invention, the adhesion promoter is selected from one or more of complex ionic potassium polyacrylate salts, polyacrylamides, hydroxypropyl guar, and carboxymethyl cellulose.
According to some embodiments of the invention, the drilling fluid system further comprises a lubricant.
According to some embodiments of the invention, the lubricant is selected from one or more of grease, polyalkylene glycol, and dodecylbenzene sulfonic acid triethanolamine.
According to some embodiments of the invention, the composition comprises the following components in parts by weight:
80-100 parts of sodium soil slurry, 0.05-0.5 part of tackifier, 0.05-2.5 parts of filtrate reducer, 1-30 parts of hydrate thermodynamic inhibitor and 0.1-2 parts of hydrate decomposition inhibitor.
According to some embodiments of the invention, 1-5 parts shale inhibitor is also included.
According to some embodiments of the invention, 1-5 parts of a lubricant is also included.
According to some embodiments of the invention, the hydrate thermodynamic inhibitor may be present in an amount of 1 part, 5 parts, 10 parts, 15 parts, 25 parts, 30 parts.
According to some embodiments of the invention, the hydrate dissociation inhibitor may be present in an amount of 0.1 part, 0.5 part, 1 part, 1.5 parts, 2 parts.
According to some embodiments of the invention, the sodium soil slurry comprises water and sodium soil in a weight ratio of 100 (2-8), preferably 100:2.
According to some embodiments of the invention, the drilling fluid has a pH of 8-9.
According to some embodiments of the invention, a pH adjuster is also included.
According to some embodiments of the invention, the pH adjuster is one or both of sodium carbonate and sodium hydroxide.
According to some embodiments of the invention, the sodium carbonate is 0-0.5 parts by weight and the sodium hydroxide is 0-0.5 parts by weight.
In a second aspect the invention provides a method of preparing the drilling fluid system of the first aspect, by mixing a bentonite slurry, a viscosifier, a fluid loss additive, a hydrate thermodynamic inhibitor, a hydrate breakdown inhibitor, optionally a shale inhibitor, optionally a lubricant and optionally a pH adjuster.
A third aspect of the invention provides the use of the drilling fluid system of the first aspect in hydrate formation operations.
The drilling fluid system is applied to oil gas and natural gas hydrate drilling engineering in hydrate stratum, and hydrate does not decompose at least for 20 hours under the conditions of simulating a hydrate reservoir layer to 2 ℃ and 10MPa, so that hydrate decomposition can be effectively inhibited, meanwhile, a wellbore environment is simulated under the conditions of 2 ℃ and 10MPa, and no hydrate is generated at least for 20 hours.
Compared with the prior art, the invention has the following beneficial effects:
(1) The drilling fluid system has good compatibility with various drilling fluid treatment agents, and still keeps good rheological property and fluid loss property under the condition of low temperature (2 ℃) on the seabed.
(2) The drilling fluid system comprises a hydrate thermodynamic inhibitor and a hydrate decomposition inhibitor, wherein the hydrate thermodynamic inhibitor can change the formation condition of the hydrate so that the formation condition of the hydrate is more severe; the hydrate decomposition inhibitor can influence the formation of hydrate crystals, and meanwhile, the high molecular chain contained in the hydrate decomposition inhibitor and the hydrate structure generate interaction, so that the resistance of the hydrate is increased during the decomposition, and the generation and the decomposition of the hydrate can be effectively inhibited by the synergistic effect of the high molecular chain and the hydrate. The stability of the well wall of the hydrate stratum can be obviously improved, and the problems of well shaft and pipeline blockage caused by the generation of natural gas hydrate and well wall instability caused by the decomposition of the hydrate at the bottom of the well are solved.
(3) The drilling fluid system has strong hydration expansion inhibition performance, and can effectively prevent unstable well wall caused by clay hydration.
(4) The drilling fluid system of the invention has the advantages of convenient preparation, simple use, low price, environmental protection and no toxicity, and meets the specific requirements of the on-site construction of hydrate stratum.
Drawings
FIG. 1 is a graph showing the variation in moles of hydrate decomposing gas under different drilling fluid formulation conditions for test example 2;
FIG. 2 is a graph showing the evaluation of the hydrate formation inhibition performance of the drilling fluid of test example 3;
fig. 3 is a graph of experimental shale expansion of drilling fluid for a hydrate formation of test example 4.
Detailed Description
In order that the invention may be more readily understood, the invention will be described in detail below with reference to the following examples, which are given by way of illustration only and are not limiting of the scope of application of the invention.
In the present invention, a complex ionic potassium polyacrylate salt (Fa-367, weight average molecular weight of 1200 ten thousand), polyacrylamide (PAM, weight average molecular weight of 1200 ten thousand), hydroxypropyl guar Gum (GRJ), and carboxymethyl cellulose (HV-CMC) were purchased from gold long chemical company, ltd;
sulfonated phenolic resin (SMP-1), sulfonated lignite resin (SD-102), carboxymethyl starch (CMS), polyamine shale inhibitor (SDJA), potassium salt humic acid shale inhibitor (KHm) and asphalt shale inhibitor are purchased from Dongying city stone Innovative technology Co., ltd;
grease (PF-LUBE), polyalkylene glycol (PAG, weight average molecular weight 10000), and triethanolamine dodecylbenzenesulfonate (ABSN) were purchased from Zhonghai oil clothing chemical Co., ltd;
ethylene Glycol (EG), sodium chloride (NaCl), potassium chloride (KCl), lecithin (Lecithin) and polyvinylpyrrolidone (PVP-K90) were purchased from Aba Ding Shiji (Shanghai) Inc.
Sodium clay was purchased from shandonghua Weishi bentonite limited.
In the invention, the rheological property and the fluid loss property of a drilling fluid system are measured by a six-speed rotary viscometer and a medium-pressure fluid loss meter.
In the invention, the hydration inhibition of the drilling fluid system is measured through a rolling dispersion experiment and a clay hydration expansion experiment, and the experimental method refers to a physical and chemical property test method of the shale in the petroleum industry standard SY-T5613-2000.
Preparation example
Sodium soil slurry is prepared, 100 parts by weight of water and 2 parts by weight of sodium soil are mixed and stirred uniformly.
Example 1
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier Fa-367, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 0.5 part of PVP-K90 and 0.5 part of lecithin.
Example 2
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier Fa-367, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 3 parts of lubricant LUBE, 1 part of shale inhibitor SDJA, 0.25 part of PVP-K90, 1 part of lecithin and 10 parts of ethylene glycol.
Example 3
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.3 part of tackifier GRJ, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 3 parts of lubricant PAG, 3 parts of shale inhibitor SDJA, 1 part of glycol and 1 part of lecithin.
Example 4
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.3 part of tackifier GRJ, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 1 part of filtrate reducer CMS, 3 parts of lubricant PAG, KHm parts of shale inhibitor, 15 parts of sodium chloride, 15 parts of ethylene glycol and 1 part of lecithin.
Example 5
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.3 part of tackifier GRJ, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 48 parts of filtrate reducer JLS-1 1, 3 parts of lubricant ABSN, 3 parts of asphalt shale inhibitor, 0.1 part of sodium chloride and 1 part of lecithin.
Example 6
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier HV-CMC, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 3 parts of lubricant LUBE, 3 parts of shale inhibitor SDJA, 0.1 part of PVP-K90 and 10 parts of ethylene glycol.
Example 7
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier PAM, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 3 parts of lubricant LUBE, 3 parts of shale inhibitor SDJA, 1 part of PVP-K90, 1 part of lecithin and 10 parts of ethylene glycol.
Example 8
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier HV-CMC, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer JLS-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 3 parts of lubricant LUBE, 3 parts of shale inhibitor SDJA, 0.05 part of PVP-K90 and 10 parts of glycol.
Example 9
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier PAM, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 3 parts of lubricant LUBE, 0.25 part of PVP-K90, 1 part of lecithin, 10 parts of ethylene glycol, KHm parts of shale inhibitor and 1 part of asphalt shale inhibitor.
Comparative example 1
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier Fa-367, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 5 parts of potassium chloride, 10 parts of sodium chloride, 0.25 part of sodium hydroxide, 1 part of shale inhibitor SDJA and 3 parts of lubricant LUBE.
Comparative example 2
A formulated water-based drilling fluid for a hydrate formation, the drilling fluid comprising: 100 parts of sodium soil slurry, 0.25 part of tackifier Fa-367, 2 parts of filtrate reducer SD-102, 0.5 part of filtrate reducer SMP-1, 0.2 part of sodium carbonate, 0.25 part of sodium hydroxide, 1 part of shale inhibitor SDJA, 3 parts of lubricant LUBE and 10 parts of glycol.
Test example 1
Low temperature rheology and fluid loss performance test:
the drilling fluid system prepared in the example is subjected to basic performance evaluation such as rheological loss, and experimental results are shown in table 1. Wherein AV represents apparent viscosity, PV represents funnel viscosity, YP represents dynamic shear force, gel represents shear force, and F L Indicating the water loss.
TABLE 1
According to the test results of table 1, it can be found that the viscosity, shear force, dynamic speed ratio and fluid loss of the drilling fluid systems of examples 1 to 9 are moderate, which is beneficial to carrying rock debris, cleaning the well bore, and the viscosity of the system increases less at low temperature, so that the rheological property of the drilling fluid at low temperature is ensured.
Test example 2
Hydrate decomposition inhibition tests were performed according to the method disclosed in patent CN108301816a for the influence of natural gas decomposition characteristics on the rating.
FIG. 1 is a graph showing the variation in moles of gas for hydrate decomposition under the conditions of the water-based drilling fluid systems described in example 1 and example 2. Example 3 reached equilibrium after 14h with a gas mole number change of 2.9; example 4 reached equilibrium after 15 hours with a gas mole number change of 2.8; example 5 reached equilibrium after 12 hours with a gas mole number change of 2.95; example 6 reached equilibrium after 14.5 hours with a gas mole number change of 2.85; example 7 reached equilibrium after 17h with a gas mole number change of 2.8; example 8 reached equilibrium after 13h with a gas mole number change of 2.9; example 9 reached equilibrium after 18h with a gas mole number change of 2.75; comparative example 2 reached equilibrium after 11 hours with a gas mole number change of 2.9. Compared with the deepwater water-based drilling fluid without the mechanical inhibitor and the decomposition inhibitor in comparative example 1 and the decomposition inhibitor in comparative example 2, the molar number of the hydrate decomposition gas rises slowly under the condition of the drilling fluid system, the equilibrium time of the system is obviously increased, and the good hydrate decomposition delaying performance is shown.
Test example 3
Hydrate formation inhibition performance tests were performed according to the method disclosed in patent CN108301816a for the influence of natural gas decomposition characteristics on the rating.
Fig. 2 is an experimental curve for evaluating the hydrate formation inhibition performance of the drilling fluid prepared in example 2, and it can be seen that the pressure in the reaction kettle in the drilling fluid system is reduced by about 0.4MPa for 24 hours, and the temperature is slightly fluctuated, and the test results of the pressure reduction of the drilling fluid prepared in examples 1 to 9 in the reaction kettle for 24 hours are shown in table 2.
TABLE 2
Compared with comparative examples 1 and 2, the drilling fluid pressures of examples 1 to 9 are all only slightly reduced, which indicates that no hydrate is generated in the system, the reduced pressure is caused by that gas is partially dissolved in the drilling fluid, no generation of hydrate is observed after the reaction kettle is opened, and the drilling fluid system provided by the invention has good hydrate generation delaying performance.
Test example 4
The water-based drilling fluids prepared in examples 1-9 were subjected to a hydration expansion experiment to examine the hydration inhibition of the drilling fluid system. Table 3 shows the results of the cuttings recovery experiments.
TABLE 3 Table 3
| Test solution | Recovery/% |
| Clean water | 3.9 |
| Example 1 | 85 |
| Example 2 | 92.76 |
| Example 3 | 90.32 |
| Example 4 | 91.23 |
| Example 5 | 92.37 |
| Example 6 | 92.46 |
| Example 7 | 91.04 |
| Example 8 | 92.24 |
| Example 9 | 91.86 |
| Comparative example 1 | 90.15 |
| Comparative example 2 | 90.35 |
As can be seen from Table 3, the recovery rate of the rock cuttings in the clear water is only 3.9%, and the recovery rate in the water-based drilling fluids prepared in examples 1-9 is more than 90%, which shows that the water-based drilling fluid system has strong rock hydration dispersion inhibition performance. Fig. 3 shows an expansion ratio experiment under the condition of clear water and the water-based drilling fluid prepared in example 2, the expansion ratio of the core 8h in the clear water can be found to be 41.2%, and the expansion ratios of the water-based drilling fluids prepared in examples 1-9 are not more than 20%, which indicates that the water-based drilling fluid system has strong rock hydration expansion inhibition performance and can effectively prevent the well wall from being unstable.
In summary, the foregoing is only a preferred embodiment of the present invention. It should be noted that other equivalent modifications and improvements will occur to those skilled in the art, and are intended to be within the scope of the present invention, as a matter of common general knowledge in the art, in light of the technical teaching provided by the present invention.
Claims (10)
1. A water-based drilling fluid system for a hydrate stratum, which is characterized by comprising sodium soil slurry, a tackifier, a filtrate reducer, a hydrate thermodynamic inhibitor and a hydrate decomposition inhibitor;
wherein the hydrate thermodynamic inhibitor is selected from one or more of ethylene glycol, sodium chloride and potassium chloride;
the hydrate decomposition inhibitor is selected from one or more of lecithin and polyvinylpyrrolidone.
2. The drilling fluid system of claim 1, further comprising a shale inhibitor;
preferably, the shale inhibitor is selected from one or more of polyamine shale inhibitors, potassium salt humic shale inhibitors and bituminous shale inhibitors.
3. Drilling fluid system according to claim 1 or 2, wherein the fluid loss additive is selected from one or more of sulphonated phenolic resin, sulphonated lignite resin and carboxymethyl starch; and/or
The tackifier is one or more selected from composite ionic potassium polyacrylate, polyacrylamide, hydroxypropyl guar gum and carboxymethyl cellulose.
4. A drilling fluid system according to any one of claims 1-3, wherein the drilling fluid system further comprises a lubricant;
preferably, the lubricant is selected from one or more of grease, polyalkylene glycol and dodecylbenzene sulfonic acid triethanolamine.
5. Drilling fluid system according to any of claims 1-4, comprising the following components in parts by weight:
80-100 parts of sodium soil slurry, 0.05-0.5 part of tackifier, 0.05-2.5 parts of filtrate reducer, 1-30 parts of hydrate thermodynamic inhibitor and 0.1-2 parts of hydrate decomposition inhibitor;
preferably, 1-5 parts of shale inhibitor is also included;
preferably, 1-5 parts of lubricant is also included.
6. Drilling fluid system according to any of claims 1-5, wherein the bentonite slurry comprises water and bentonite in a weight ratio of 100 (2-8).
7. Drilling fluid system according to any of claims 1-6, characterized in that the pH of the drilling fluid system is 8-9.
8. The drilling fluid system of any one of claims 1-7, further comprising a pH adjuster;
preferably, the pH regulator is one or two of sodium carbonate and sodium hydroxide;
preferably, the sodium carbonate-sodium hydroxide composite material also comprises 0-0.5 part by weight of sodium carbonate and 0-0.5 part by weight of sodium hydroxide.
9. A method of preparing a drilling fluid system according to any one of claims 1 to 8, characterized in that a sodium clay slurry, a viscosifier, a fluid loss additive, a hydrate thermodynamic inhibitor, a hydrate breakdown inhibitor, an optional shale inhibitor, an optional lubricant and an optional pH adjuster are mixed.
10. Use of the drilling fluid system of any one of claims 1-8 in hydrate formation operations.
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