CN115124159A - Shale gas fracturing flowback fluid composite treatment fluid and preparation method and application thereof - Google Patents
Shale gas fracturing flowback fluid composite treatment fluid and preparation method and application thereof Download PDFInfo
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- CN115124159A CN115124159A CN202110330723.8A CN202110330723A CN115124159A CN 115124159 A CN115124159 A CN 115124159A CN 202110330723 A CN202110330723 A CN 202110330723A CN 115124159 A CN115124159 A CN 115124159A
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- fluid
- shale gas
- gas fracturing
- component
- composite treatment
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- 239000012530 fluid Substances 0.000 title claims abstract description 294
- 239000002131 composite material Substances 0.000 title claims abstract description 91
- 238000002360 preparation method Methods 0.000 title claims abstract description 13
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 25
- 239000007788 liquid Substances 0.000 claims abstract description 23
- 238000005189 flocculation Methods 0.000 claims abstract description 21
- 230000016615 flocculation Effects 0.000 claims abstract description 21
- 230000001954 sterilising effect Effects 0.000 claims abstract description 20
- 238000004659 sterilization and disinfection Methods 0.000 claims abstract description 17
- -1 iron ions Chemical class 0.000 claims abstract description 13
- UEZVMMHDMIWARA-UHFFFAOYSA-M phosphonate Chemical compound [O-]P(=O)=O UEZVMMHDMIWARA-UHFFFAOYSA-M 0.000 claims abstract description 13
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 claims abstract description 11
- 230000007935 neutral effect Effects 0.000 claims abstract description 11
- XEEYBQQBJWHFJM-UHFFFAOYSA-N iron Substances [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 claims abstract description 10
- 229910052742 iron Inorganic materials 0.000 claims abstract description 10
- 230000003311 flocculating effect Effects 0.000 claims abstract description 5
- 238000000034 method Methods 0.000 claims description 85
- 238000003756 stirring Methods 0.000 claims description 63
- 125000002091 cationic group Chemical group 0.000 claims description 31
- 229920002401 polyacrylamide Polymers 0.000 claims description 31
- 230000000844 anti-bacterial effect Effects 0.000 claims description 22
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical class O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 20
- 239000003899 bactericide agent Substances 0.000 claims description 18
- 238000002156 mixing Methods 0.000 claims description 12
- 239000002994 raw material Substances 0.000 claims description 7
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 claims description 6
- WSFSSNUMVMOOMR-UHFFFAOYSA-N Formaldehyde Chemical compound O=C WSFSSNUMVMOOMR-UHFFFAOYSA-N 0.000 claims description 6
- 150000001299 aldehydes Chemical class 0.000 claims description 6
- MGIYRDNGCNKGJU-UHFFFAOYSA-N isothiazolinone Chemical compound O=C1C=CSN1 MGIYRDNGCNKGJU-UHFFFAOYSA-N 0.000 claims description 6
- 150000003242 quaternary ammonium salts Chemical class 0.000 claims description 6
- 229940100555 2-methyl-4-isothiazolin-3-one Drugs 0.000 claims description 5
- SXRSQZLOMIGNAQ-UHFFFAOYSA-N Glutaraldehyde Chemical compound O=CCCCC=O SXRSQZLOMIGNAQ-UHFFFAOYSA-N 0.000 claims description 5
- 239000013530 defoamer Substances 0.000 claims description 5
- 239000008394 flocculating agent Substances 0.000 claims description 5
- BEGLCMHJXHIJLR-UHFFFAOYSA-N methylisothiazolinone Chemical compound CN1SC=CC1=O BEGLCMHJXHIJLR-UHFFFAOYSA-N 0.000 claims description 5
- 229920001296 polysiloxane Polymers 0.000 claims description 5
- 230000008569 process Effects 0.000 claims description 5
- HGINCPLSRVDWNT-UHFFFAOYSA-N Acrolein Chemical compound C=CC=O HGINCPLSRVDWNT-UHFFFAOYSA-N 0.000 claims description 4
- OKIZCWYLBDKLSU-UHFFFAOYSA-M N,N,N-Trimethylmethanaminium chloride Chemical compound [Cl-].C[N+](C)(C)C OKIZCWYLBDKLSU-UHFFFAOYSA-M 0.000 claims description 4
- 239000004721 Polyphenylene oxide Substances 0.000 claims description 4
- NAQMVNRVTILPCV-UHFFFAOYSA-N hexane-1,6-diamine Chemical compound NCCCCCCN NAQMVNRVTILPCV-UHFFFAOYSA-N 0.000 claims description 4
- 229920000570 polyether Polymers 0.000 claims description 4
- ZLMJMSJWJFRBEC-UHFFFAOYSA-N Potassium Chemical compound [K] ZLMJMSJWJFRBEC-UHFFFAOYSA-N 0.000 claims description 3
- SNAAJJQQZSMGQD-UHFFFAOYSA-N aluminum magnesium Chemical compound [Mg].[Al] SNAAJJQQZSMGQD-UHFFFAOYSA-N 0.000 claims description 3
- JBIROUFYLSSYDX-UHFFFAOYSA-M benzododecinium chloride Chemical group [Cl-].CCCCCCCCCCCC[N+](C)(C)CC1=CC=CC=C1 JBIROUFYLSSYDX-UHFFFAOYSA-M 0.000 claims description 3
- 239000011591 potassium Substances 0.000 claims description 3
- 229910052700 potassium Inorganic materials 0.000 claims description 3
- BPSYZMLXRKCSJY-UHFFFAOYSA-N 1,3,2-dioxaphosphepan-2-ium 2-oxide Chemical compound O=[P+]1OCCCCO1 BPSYZMLXRKCSJY-UHFFFAOYSA-N 0.000 claims description 2
- 229940100484 5-chloro-2-methyl-4-isothiazolin-3-one Drugs 0.000 claims description 2
- KHSLHYAUZSPBIU-UHFFFAOYSA-M benzododecinium bromide Chemical compound [Br-].CCCCCCCCCCCC[N+](C)(C)CC1=CC=CC=C1 KHSLHYAUZSPBIU-UHFFFAOYSA-M 0.000 claims description 2
- OCBHHZMJRVXXQK-UHFFFAOYSA-M benzyl-dimethyl-tetradecylazanium;chloride Chemical compound [Cl-].CCCCCCCCCCCCCC[N+](C)(C)CC1=CC=CC=C1 OCBHHZMJRVXXQK-UHFFFAOYSA-M 0.000 claims description 2
- DHNRXBZYEKSXIM-UHFFFAOYSA-N chloromethylisothiazolinone Chemical compound CN1SC(Cl)=CC1=O DHNRXBZYEKSXIM-UHFFFAOYSA-N 0.000 claims description 2
- DDXLVDQZPFLQMZ-UHFFFAOYSA-M dodecyl(trimethyl)azanium;chloride Chemical compound [Cl-].CCCCCCCCCCCC[N+](C)(C)C DDXLVDQZPFLQMZ-UHFFFAOYSA-M 0.000 claims description 2
- OIPXXWBYRWQVLJ-UHFFFAOYSA-G heptasodium;[2-[2-[bis(phosphonatomethyl)amino]ethyl-(phosphonatomethyl)amino]ethyl-(phosphonomethyl)amino]methyl-hydroxyphosphinate Chemical compound [Na+].[Na+].[Na+].[Na+].[Na+].[Na+].[Na+].OP(=O)([O-])CN(CP([O-])([O-])=O)CCN(CP([O-])(=O)O)CCN(CP(O)([O-])=O)CP([O-])([O-])=O OIPXXWBYRWQVLJ-UHFFFAOYSA-G 0.000 claims description 2
- QPTMDBQLCWRDCK-UHFFFAOYSA-I pentasodium;[2-[bis[[hydroxy(oxido)phosphoryl]methyl]amino]ethyl-(phosphonatomethyl)amino]methyl-hydroxyphosphinate Chemical compound [Na+].[Na+].[Na+].[Na+].[Na+].OP([O-])(=O)CN(CP(O)([O-])=O)CCN(CP(O)([O-])=O)CP([O-])([O-])=O QPTMDBQLCWRDCK-UHFFFAOYSA-I 0.000 claims description 2
- QRIAWZKHYOWOAR-UHFFFAOYSA-I pentasodium;[bis[2-[bis[[hydroxy(oxido)phosphoryl]methyl]amino]ethyl]amino]methyl-hydroxyphosphinate Chemical compound [Na+].[Na+].[Na+].[Na+].[Na+].OP(=O)([O-])CN(CP(O)([O-])=O)CCN(CP([O-])(=O)O)CCN(CP(O)([O-])=O)CP(O)([O-])=O QRIAWZKHYOWOAR-UHFFFAOYSA-I 0.000 claims description 2
- 239000007787 solid Substances 0.000 claims description 2
- 230000003115 biocidal effect Effects 0.000 claims 1
- 239000003139 biocide Substances 0.000 claims 1
- XQRLCLUYWUNEEH-UHFFFAOYSA-L diphosphonate(2-) Chemical compound [O-]P(=O)OP([O-])=O XQRLCLUYWUNEEH-UHFFFAOYSA-L 0.000 claims 1
- 230000005764 inhibitory process Effects 0.000 abstract description 26
- 230000007797 corrosion Effects 0.000 abstract description 25
- 238000005260 corrosion Methods 0.000 abstract description 25
- 239000007789 gas Substances 0.000 description 171
- 239000006260 foam Substances 0.000 description 27
- 238000005259 measurement Methods 0.000 description 16
- 241000894006 Bacteria Species 0.000 description 15
- 238000002474 experimental method Methods 0.000 description 15
- 239000007864 aqueous solution Substances 0.000 description 14
- 238000011084 recovery Methods 0.000 description 10
- 239000000725 suspension Substances 0.000 description 10
- 230000000694 effects Effects 0.000 description 9
- 239000000243 solution Substances 0.000 description 9
- 239000003921 oil Substances 0.000 description 8
- 239000002518 antifoaming agent Substances 0.000 description 7
- 239000000126 substance Substances 0.000 description 7
- 239000003795 chemical substances by application Substances 0.000 description 6
- 239000003112 inhibitor Substances 0.000 description 6
- XUIMIQQOPSSXEZ-UHFFFAOYSA-N Silicon Chemical compound [Si] XUIMIQQOPSSXEZ-UHFFFAOYSA-N 0.000 description 5
- 238000011156 evaluation Methods 0.000 description 5
- 229910052710 silicon Inorganic materials 0.000 description 5
- 239000010703 silicon Substances 0.000 description 5
- 239000002699 waste material Substances 0.000 description 5
- 229910021645 metal ion Inorganic materials 0.000 description 4
- 239000003995 emulsifying agent Substances 0.000 description 3
- 230000003647 oxidation Effects 0.000 description 3
- 238000007254 oxidation reaction Methods 0.000 description 3
- 239000002244 precipitate Substances 0.000 description 3
- 239000002455 scale inhibitor Substances 0.000 description 3
- 239000000377 silicon dioxide Substances 0.000 description 3
- 239000002351 wastewater Substances 0.000 description 3
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 2
- MBMLMWLHJBBADN-UHFFFAOYSA-N Ferrous sulfide Chemical compound [Fe]=S MBMLMWLHJBBADN-UHFFFAOYSA-N 0.000 description 2
- RQNVGUOKYSZUJN-UHFFFAOYSA-N [K].P1(=O)OC(CO)OP(O1)=O Chemical compound [K].P1(=O)OC(CO)OP(O1)=O RQNVGUOKYSZUJN-UHFFFAOYSA-N 0.000 description 2
- AZDRQVAHHNSJOQ-UHFFFAOYSA-N alumane Chemical class [AlH3] AZDRQVAHHNSJOQ-UHFFFAOYSA-N 0.000 description 2
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 2
- 239000003638 chemical reducing agent Substances 0.000 description 2
- KRKNYBCHXYNGOX-UHFFFAOYSA-N citric acid Chemical compound OC(=O)CC(O)(C(O)=O)CC(O)=O KRKNYBCHXYNGOX-UHFFFAOYSA-N 0.000 description 2
- 239000000084 colloidal system Substances 0.000 description 2
- 238000007796 conventional method Methods 0.000 description 2
- 239000000839 emulsion Substances 0.000 description 2
- 238000001914 filtration Methods 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 2
- 244000005700 microbiome Species 0.000 description 2
- 239000001301 oxygen Substances 0.000 description 2
- 229910052760 oxygen Inorganic materials 0.000 description 2
- HRPVXLWXLXDGHG-UHFFFAOYSA-N Acrylamide Chemical compound NC(=O)C=C HRPVXLWXLXDGHG-UHFFFAOYSA-N 0.000 description 1
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- 229940120146 EDTMP Drugs 0.000 description 1
- 208000035126 Facies Diseases 0.000 description 1
- JLVVSXFLKOJNIY-UHFFFAOYSA-N Magnesium ion Chemical compound [Mg+2] JLVVSXFLKOJNIY-UHFFFAOYSA-N 0.000 description 1
- 229910004298 SiO 2 Inorganic materials 0.000 description 1
- 230000002378 acidificating effect Effects 0.000 description 1
- DIZPMCHEQGEION-UHFFFAOYSA-H aluminium sulfate (anhydrous) Chemical compound [Al+3].[Al+3].[O-]S([O-])(=O)=O.[O-]S([O-])(=O)=O.[O-]S([O-])(=O)=O DIZPMCHEQGEION-UHFFFAOYSA-H 0.000 description 1
- 229960004543 anhydrous citric acid Drugs 0.000 description 1
- 238000009395 breeding Methods 0.000 description 1
- 230000001488 breeding effect Effects 0.000 description 1
- 229910001424 calcium ion Inorganic materials 0.000 description 1
- 230000003197 catalytic effect Effects 0.000 description 1
- 239000013522 chelant Substances 0.000 description 1
- 239000000701 coagulant Substances 0.000 description 1
- 230000015271 coagulation Effects 0.000 description 1
- 238000005345 coagulation Methods 0.000 description 1
- 238000005536 corrosion prevention Methods 0.000 description 1
- 239000007822 coupling agent Substances 0.000 description 1
- 239000003431 cross linking reagent Substances 0.000 description 1
- 230000007547 defect Effects 0.000 description 1
- 230000032798 delamination Effects 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 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 1
- 238000004090 dissolution Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000003814 drug Substances 0.000 description 1
- DUYCTCQXNHFCSJ-UHFFFAOYSA-N dtpmp Chemical compound OP(=O)(O)CN(CP(O)(O)=O)CCN(CP(O)(=O)O)CCN(CP(O)(O)=O)CP(O)(O)=O DUYCTCQXNHFCSJ-UHFFFAOYSA-N 0.000 description 1
- NFDRPXJGHKJRLJ-UHFFFAOYSA-N edtmp Chemical compound OP(O)(=O)CN(CP(O)(O)=O)CCN(CP(O)(O)=O)CP(O)(O)=O NFDRPXJGHKJRLJ-UHFFFAOYSA-N 0.000 description 1
- 238000005868 electrolysis reaction Methods 0.000 description 1
- 238000005187 foaming Methods 0.000 description 1
- 150000004676 glycans Chemical class 0.000 description 1
- 229920001519 homopolymer Polymers 0.000 description 1
- 230000003301 hydrolyzing effect Effects 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-M hydroxide Chemical compound [OH-] XLYOFNOQVPJJNP-UHFFFAOYSA-M 0.000 description 1
- 239000003999 initiator Substances 0.000 description 1
- 229910001425 magnesium ion Inorganic materials 0.000 description 1
- 239000011259 mixed solution Substances 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 239000000178 monomer Substances 0.000 description 1
- 239000007800 oxidant agent Substances 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- 230000020477 pH reduction Effects 0.000 description 1
- JRKICGRDRMAZLK-UHFFFAOYSA-L peroxydisulfate Chemical compound [O-]S(=O)(=O)OOS([O-])(=O)=O JRKICGRDRMAZLK-UHFFFAOYSA-L 0.000 description 1
- 230000000379 polymerizing effect Effects 0.000 description 1
- 229920001282 polysaccharide Polymers 0.000 description 1
- 239000005017 polysaccharide Substances 0.000 description 1
- 235000019353 potassium silicate Nutrition 0.000 description 1
- 238000001556 precipitation Methods 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 238000004064 recycling Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 238000004062 sedimentation Methods 0.000 description 1
- 239000010865 sewage Substances 0.000 description 1
- 235000012239 silicon dioxide Nutrition 0.000 description 1
- 239000010802 sludge Substances 0.000 description 1
- NTHWMYGWWRZVTN-UHFFFAOYSA-N sodium silicate Chemical compound [Na+].[Na+].[O-][Si]([O-])=O NTHWMYGWWRZVTN-UHFFFAOYSA-N 0.000 description 1
- 238000001179 sorption measurement Methods 0.000 description 1
- 239000011550 stock solution Substances 0.000 description 1
- 238000013517 stratification Methods 0.000 description 1
- FZUJWWOKDIGOKH-UHFFFAOYSA-N sulfuric acid hydrochloride Chemical compound Cl.OS(O)(=O)=O FZUJWWOKDIGOKH-UHFFFAOYSA-N 0.000 description 1
- 239000004094 surface-active agent Substances 0.000 description 1
- 230000002195 synergetic effect Effects 0.000 description 1
- 239000008399 tap water Substances 0.000 description 1
- 235000020679 tap water Nutrition 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F9/00—Multistage treatment of water, waste water or sewage
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F1/00—Treatment of water, waste water, or sewage
- C02F1/20—Treatment of water, waste water, or sewage by degassing, i.e. liberation of dissolved gases
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F1/00—Treatment of water, waste water, or sewage
- C02F1/28—Treatment of water, waste water, or sewage by sorption
- C02F1/281—Treatment of water, waste water, or sewage by sorption using inorganic sorbents
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F1/00—Treatment of water, waste water, or sewage
- C02F1/50—Treatment of water, waste water, or sewage by addition or application of a germicide or by oligodynamic treatment
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F1/00—Treatment of water, waste water, or sewage
- C02F1/52—Treatment of water, waste water, or sewage by flocculation or precipitation of suspended impurities
- C02F1/54—Treatment of water, waste water, or sewage by flocculation or precipitation of suspended impurities using organic material
- C02F1/56—Macromolecular compounds
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F2101/00—Nature of the contaminant
- C02F2101/30—Organic compounds
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F2103/00—Nature of the water, waste water, sewage or sludge to be treated
- C02F2103/10—Nature of the water, waste water, sewage or sludge to be treated from quarries or from mining activities
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F2303/00—Specific treatment goals
- C02F2303/04—Disinfection
-
- C—CHEMISTRY; METALLURGY
- C02—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F—TREATMENT OF WATER, WASTE WATER, SEWAGE, OR SLUDGE
- C02F5/00—Softening water; Preventing scale; Adding scale preventatives or scale removers to water, e.g. adding sequestering agents
- C02F5/08—Treatment of water with complexing chemicals or other solubilising agents for softening, scale prevention or scale removal, e.g. adding sequestering agents
- C02F5/10—Treatment of water with complexing chemicals or other solubilising agents for softening, scale prevention or scale removal, e.g. adding sequestering agents using organic substances
- C02F5/14—Treatment of water with complexing chemicals or other solubilising agents for softening, scale prevention or scale removal, e.g. adding sequestering agents using organic substances containing phosphorus
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Hydrology & Water Resources (AREA)
- Engineering & Computer Science (AREA)
- Environmental & Geological Engineering (AREA)
- Water Supply & Treatment (AREA)
- Chemical & Material Sciences (AREA)
- Organic Chemistry (AREA)
- Separation Of Suspended Particles By Flocculating Agents (AREA)
Abstract
The invention provides a shale gas fracturing flowback fluid composite treatment fluid and a preparation method and application thereof, wherein the shale gas fracturing flowback fluid composite treatment fluid comprises 3-6% of neutral phosphonate component, 5-12% of inorganic flocculation component, 1.5-3% of sterilization component, 2-5% of water-soluble defoaming component and the balance of water, wherein the contents of the sterilization component and the water-soluble defoaming component are respectively calculated by the contents of effective components in the sterilization component and the water-soluble defoaming component, and the total weight of the shale gas fracturing flowback fluid composite treatment fluid is 100%; the inorganic flocculating component is free of iron ions and sulfate ions. The composite treatment liquid for the shale gas fracturing flowback fluid provided by the invention has multiple functions of scale inhibition, corrosion inhibition, flocculation, sterilization, defoaming and the like, and has a good application prospect in the treatment of the shale gas fracturing flowback fluid.
Description
Technical Field
The invention relates to a shale gas fracturing flow-back fluid composite treatment fluid, a preparation method and application thereof, and belongs to the technical field of sewage treatment.
Background
The shale gas development requires large water amount, and the generated fracturing flowback fluid is large and needs to be treated. Currently, there are many techniques related to treating fracturing flowback fluid in the prior art, such as: chinese patent CN110615514A discloses an aluminum salt microorganism composite flocculant for treating shale gas drilling wastewater, and the preparation method of the flocculant comprises the following steps: firstly, PDMDAAC (dimethyl diallyl ammonium chloride homopolymer) is added into an aluminum sulfate solution to obtain PAS-PDM solution, then polysaccharide extracted from mycobacteria is added into a mixed solution, and the mixture is stirred to obtain the stable aluminum salt microorganism composite flocculant, wherein the COD removal rate can be increased by 24.10-12.60% and the chroma removal rate can be increased by 50-10% compared with the conventional coagulant used in the field.
Chinese patent CN102786186A discloses a shale gas fracturing flowback waste liquid treatment method, which comprises coagulation, micro-electrolysis, Fenton composite persulfate catalytic oxidation, flocculation precipitation, hydrolytic acidification, biochemistry and adsorption filtration treatment, and the wastewater treated by the treatment method can be discharged and recycled after reaching standards, but the treatment process of the treatment method is complicated.
Chinese patent CN103043831A discloses a method for treating continental facies shale gas well fracturing operation waste liquid, which comprises the following steps: firstly, adding a pH regulator into the waste liquid to regulate the pH value of the waste liquid to 4.5-6.5, then adding an oxidant to carry out oxidation and viscosity reduction, then regulating the pH value of the waste liquid to 7.0-8.5 again, and finally recycling the waste water for preparing fracturing fluid or reinjecting stratum through flocculation, sedimentation and filtration.
Chinese patent CN106145296A discloses a preparation method of a composite flocculant for reuse pretreatment of a fracturing flowback fluid, wherein the raw materials of the flocculant comprise a high-viscosity biological flocculant, polyaluminium chloride, anhydrous citric acid and tap water, and the flocculant solves the problems that the existing shale gas fracturing flowback fluid flocculation treatment agent is generally difficult to degrade and can cause secondary pollution or introduce high-valence metal ions to cause great influence on the performance of the fracturing fluid.
Chinese patent CN104292386A discloses a composite flocculant for flocculation treatment of fracturing flowback fluid and a preparation method thereof, wherein the raw materials of the flocculant comprise water glass, a coupling agent, an acrylamide monomer, a cationic monomer, a cross-linking agent and an initiator, and the flocculant is prepared by polymerizing water solutionPrepared by a legal method, the flocculating agent is SiO 2 -cationic polyacrylamide composite flocculant.
The fracturing flow-back fluid treatment agents are mainly combined and applied by various flocculation and oxidation treatment agents, and a single agent has a single function, does not have the function of multiple effects of one agent, and also has multiple treatment effects of scale inhibition, corrosion inhibition, flocculation, sterilization and defoaming.
Therefore, the provision of a novel shale gas fracturing flowback fluid composite treatment fluid, and a preparation method and application thereof have become technical problems to be solved urgently in the field.
Disclosure of Invention
In order to solve the defects and shortcomings, the invention provides a shale gas fracturing flow-back fluid composite treatment fluid.
The invention also aims to provide a preparation method of the shale gas fracturing flow-back fluid composite treatment fluid.
The invention also aims to provide application of the shale gas fracturing flow-back fluid composite treatment fluid in treatment of shale gas fracturing flow-back fluid.
The invention also aims to provide a method for treating the shale gas fracturing flow-back fluid, wherein the method utilizes the shale gas fracturing flow-back fluid composite treatment fluid.
In order to achieve the above object, in one aspect, the present invention provides a shale gas fracturing flow-back fluid composite treatment fluid, wherein the shale gas fracturing flow-back fluid composite treatment fluid comprises, by taking the total weight of the shale gas fracturing flow-back fluid composite treatment fluid as 100%, 3 to 6% of a neutral phosphonate component, 5 to 12% of an inorganic flocculating component, 1.5 to 3% of a sterilizing component, 2 to 5% of a water-soluble defoaming component and the balance of water, wherein the contents of the sterilizing component and the water-soluble defoaming component are respectively calculated by the contents of effective components in the sterilizing component and the water-soluble defoaming component;
the inorganic flocculating component is free of iron ions and sulfate ions.
In the invention, the neutrality means that the pH value of the phosphonate stock solution or the phosphonate aqueous solution (the mass concentration is 6%) is 6-8.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the neutral phosphonate component includes one or a combination of several of tetrasodium amino trimethylene phosphonate, potassium hydroxyethylidene diphosphonate, pentasodium ethylene diamine tetramethylene phosphonate, pentasodium diethylene triamine pentamethylene phosphonate, heptasodium diethylene triamine pentamethylene phosphonate, and potassium hexamethylene diamine tetramethylene phosphonate.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the inorganic flocculation component includes one or more of polyaluminium chloride, polyaluminium chloride sulfate and aluminum magnesium polysilicate.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the bactericidal component includes one or a combination of several of aldehyde bactericides, quaternary ammonium salt bactericides and isothiazolinone bactericides.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the aldehyde bactericide includes one or a combination of more of glutaraldehyde, formaldehyde and acrolein.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the aldehyde bactericide is glutaraldehyde.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the quaternary ammonium salt bactericide includes one or a combination of more of tetradecyl dimethyl benzyl ammonium chloride, dodecyl trimethyl ammonium chloride, dodecyl dimethyl benzyl ammonium bromide and tetramethyl ammonium chloride.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the quaternary ammonium salt bactericide is dodecyl dimethyl benzyl ammonium chloride or tetramethylammonium chloride.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the isothiazolinone bactericide comprises methylisothiazolinone and/or methylchloroisothiazolinone.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the isothiazolinone bactericide is methylisothiazolinone.
As a specific embodiment of the composite treatment fluid for shale gas fracturing flowback fluid, the water-soluble defoaming component comprises one or more of a polyether defoaming agent and a silicone defoaming agent.
In the shale gas fracturing flow-back fluid composite treatment fluid, a neutral phosphonate component is used as a scale inhibition component, and can chelate high-valence metal ions such as calcium ions, magnesium ions and the like in the shale gas fracturing flow-back fluid, so that scaling blockage of pipelines, equipment, filters and the like in the subsequent water treatment process is avoided; the neutral phosphonate component and the inorganic flocculation component, the sterilization component and the water-soluble defoaming component in the shale gas fracturing flowback fluid composite treatment fluid are compounded to have excellent synergistic effect; the neutral phosphonate component is adopted as the scale inhibition component, so that the problem that the hardness of the shale gas fracturing flowback fluid is increased due to the dissolution of an acidic scale inhibitor on precipitated high-valence metal ion precipitate (insoluble carbonate and/or insoluble hydroxide) and/or colloid in the shale gas fracturing flowback fluid can be avoided, and the problem that the alkaline scale inhibitor reacts with a flocculation component in the shale gas fracturing flowback fluid composite treatment fluid to generate precipitate can also be avoided; meanwhile, the neutral phosphonate can also play a certain role in corrosion prevention;
the inorganic flocculation component can flocculate and settle shale gas fracturing flow-back fluid, so that the content of suspended matters is greatly reduced; the inorganic flocculation component which does not contain iron ions and sulfate ions and is used by the invention can avoid the influence of the iron ions on the performance of the resistance reducing agent when the shale gas fracturing flow-back fluid is recycled, can also avoid the problem that the flow-back fluid is blackened because of ferrous sulfide generated by combining hydrogen sulfide generated by sulfate reducing bacteria and the iron ions, and can also avoid the introduction of sulfate radicals to provide a necessary environment for the growth of the sulfate reducing bacteria;
the bactericidal component has broad-spectrum bactericidal effect and can inhibit the growth of bacteria within a certain period of time.
The water-soluble defoaming component can avoid the foaming problem of the shale gas fracturing flowback fluid caused by the surfactant, and the problems of COD (chemical oxygen demand) increase, agent demulsification and delamination and the like caused by the use of the conventional organic silicon oil emulsion defoaming agent (oil phase containing silicon oil, precipitated silicon dioxide, emulsifier and other substances) can be avoided by using one or a combination of more of polyether defoaming agent and silicone defoaming agent as the water-soluble defoaming component.
On the other hand, the invention also provides a preparation method of the shale gas fracturing flow-back fluid composite treatment fluid, wherein the preparation method comprises the following steps:
adding a water-soluble defoaming component into water under the condition of stirring, adding a solid component in raw materials for preparing the shale gas fracturing flow-back fluid composite treatment fluid after uniformly stirring, uniformly stirring to form a turbid liquid, adding a liquid component in the raw materials into the turbid liquid, and uniformly stirring to obtain the turbid liquid, namely the shale gas fracturing flow-back fluid composite treatment fluid.
In another aspect, the invention also provides application of the shale gas fracturing flow-back fluid composite treatment fluid in treatment of shale gas fracturing flow-back fluid.
In another aspect, the present invention further provides a method for treating a shale gas fracturing flow-back fluid, where the method for treating a shale gas fracturing flow-back fluid uses the above composite treating fluid, and includes:
and adding the shale gas fracturing flow-back fluid composite treatment liquid into the shale gas fracturing flow-back fluid, uniformly mixing, adding a flocculant solution, uniformly mixing, and settling.
As a specific embodiment of the above method of the present invention, based on the total volume of the shale gas fracturing flow-back fluid, the usage amount of the shale gas fracturing flow-back fluid composite treatment fluid is 0.1 to 0.8%, and the usage amount of the flocculant is 5 to 20 mg/L.
In a specific embodiment of the above method of the present invention, the flocculant is cationic polyacrylamide.
In an embodiment of the above method of the present invention, the cationic polyacrylamide has a viscosity average molecular weight of 150 to 2000 ten thousand.
In the treatment method, the shale gas fracturing flow-back fluid composite treatment fluid is added into the shale gas fracturing flow-back fluid for flocculation, and then a flocculating agent solution (such as a cationic polyacrylamide solution) is added to enable flocs to be gathered and enlarged and settle down by gravity.
In another aspect, the present invention further provides a method for treating a shale gas fracturing flow-back fluid, where the method for treating a shale gas fracturing flow-back fluid uses the above composite treating fluid, and includes:
adding modified diatomite into the shale gas fracturing flow-back fluid, uniformly mixing, then adding the shale gas fracturing flow-back fluid composite treatment fluid, uniformly mixing, then adding a flocculant solution, uniformly mixing, and then settling.
As a specific embodiment of the above method of the present invention, based on the total volume of the shale gas fracturing flow-back fluid, the usage amount of the modified diatomite is 100-500mg/L, the usage amount of the composite treatment fluid for shale gas fracturing flow-back fluid is 0.1-0.8%, and the usage amount of the flocculant is 5-20 mg/L.
In a specific embodiment of the above method of the present invention, the flocculant is cationic polyacrylamide.
In an embodiment of the above method of the present invention, the cationic polyacrylamide has a viscosity average molecular weight of 150 to 2000 ten thousand.
In the treatment method, firstly modified diatomite is added into the shale gas fracturing flow-back fluid for flocculation, then the shale gas fracturing flow-back fluid composite treatment fluid is added for flocculation, and finally a flocculant solution (such as a cationic polyacrylamide solution) is added to enable flocs to be aggregated and enlarged and settled by means of gravity.
Wherein, when the shale gas fracturing flow-back fluid is treated, the modified diatomite is added, so that the settling time of the sludge after flocculation settling is faster, and the dewatering performance is better.
Compared with the prior art, the technical scheme of the invention can achieve the following effects:
1) the composite treatment liquid for the shale gas fracturing flowback fluid provided by the invention simultaneously comprises a neutral phosphonate component, an inorganic flocculation component without iron ions and sulfate ions, a sterilization component and a water-soluble defoaming component, and can avoid the problem that a single scale inhibitor, a corrosion inhibitor, a flocculating agent, a bactericide and a defoaming agent cannot be directly mixed and need to be separately injected;
2) the composite treatment liquid for the shale gas fracturing flow-back fluid does not contain iron ions, so that the influence of the iron ions on the resistance reducing performance of a resistance reducing agent during the return of the shale gas fracturing flow-back fluid is avoided, and the problem of water blackening caused by the fact that the iron ions are combined with hydrogen sulfide generated by sulfate reducing bacteria to generate ferrous sulfide is also avoided;
3) the shale gas fracturing flowback fluid composite treatment liquid provided by the invention does not contain sulfate (sulfate ions), so that a great deal of sulfate reducing bacteria is prevented from breeding;
4) the shale gas fracturing flow-back fluid composite treatment fluid provided by the invention adopts a neutral phosphonate component as a scale inhibition component, so that high-valence metal ion precipitates and/or colloids which are already precipitated in the shale gas fracturing flow-back fluid are not dissolved, and the hardness of the shale gas fracturing flow-back fluid is prevented from being increased;
5) the defoaming component adopted by the composite treatment fluid for the shale gas fracturing flow-back fluid provided by the invention does not contain substances such as an oil phase such as silicon oil, precipitated silica, an emulsifier and the like, can be directly dissolved in water, can avoid the problem that a large amount of foam is generated in the treatment process of the shale gas fracturing flow-back fluid due to air floatation and impact, can also avoid the problem that the foam is generated in subsequent industrial application after the treatment of the shale gas fracturing flow-back fluid, and can not cause the problems of COD (chemical oxygen demand) increase, demulsification and stratification of a medicament and the like caused by the use of the conventional organic silicon oil emulsion defoamer (substances such as the oil phase such as silicon oil, the precipitated silica, the emulsifier and the like);
6) in conclusion, the composite treatment fluid for the shale gas fracturing flowback fluid provided by the invention has multiple functions of scale inhibition, corrosion inhibition, flocculation, sterilization, defoaming and the like, and has a good application prospect in the treatment of the shale gas fracturing flowback fluid.
Detailed Description
In order to clearly understand the technical features, objects and advantages of the present invention, the following detailed description of the technical solutions of the present invention will be made with reference to the following specific examples, which should not be construed as limiting the implementable scope of the present invention.
In the following specific examples, those whose operations are not indicated by the conditions are conducted according to the conventional conditions or the conditions recommended by the manufacturer, and those whose raw materials are not indicated by the manufacturer and those whose specifications are commercially available are conventional products.
Example 1
The embodiment provides a shale gas fracturing flow-back fluid composite treatment fluid which is prepared by adopting a method comprising the following steps:
adding 777g of water into a 1000mL beaker, adding 28g of silicone defoamer under the stirring condition of 300rpm, and stirring for 5 min; then, under the stirring condition of 300rpm, 35g of diethylenetriamine penta (methylene phosphonic acid) pentasodium and 100g of polyaluminium chloride are sequentially added, and stirred for 15min to form uniform suspension; and then adding 60g of glutaraldehyde aqueous solution with the weight concentration of 50% under the stirring condition of 300rpm, and continuing stirring for 10min to obtain uniform suspension, namely the shale gas fracturing flowback fluid composite treatment fluid.
Example 2
The embodiment provides a shale gas fracturing flow-back fluid composite treatment fluid which is prepared by adopting a method comprising the following steps:
755g of water is added into a 1000mL beaker, and 35g of silicone defoaming agent is added under the stirring condition of 300rpm and stirred for 5 min; then, under the stirring condition of 300rpm, adding 45g of ethylenediamine tetramethylene phosphonic acid pentasodium and 110g of polyaluminum chloride in sequence, and stirring for 15min to form uniform suspension; and then adding 55g of dodecyl dimethyl benzyl ammonium chloride aqueous solution with the weight concentration of 44% under the stirring condition of 300rpm, and continuously stirring for 10min to obtain uniform suspension, namely the shale gas fracturing flowback fluid composite treatment fluid.
Example 3
The embodiment provides a shale gas fracturing flowback fluid composite treatment fluid which is prepared by adopting a method comprising the following steps of:
477g of water is added into a 1000mL beaker, 48g of polyether defoamer is added under the stirring condition of 300rpm, and the stirring is carried out for 5 min; then, under the stirring condition of 300rpm, 55g of potassium hydroxyethylidene diphosphonate and 120g of aluminum magnesium polysilicate are sequentially added, and stirring is carried out for 15min to form uniform suspension; and adding 300g of methylisothiazolinone aqueous solution with the weight concentration of 9.5% under the stirring condition of 300rpm, and continuously stirring for 10min to obtain uniform suspension, namely the shale gas fracturing flowback fluid composite treatment fluid.
Application example 1
The application example provides a method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid composite treatment fluid provided in embodiment 1 comprises the following steps:
adding 200g of water into a 250mL beaker, slowly adding 1g of cationic polyacrylamide flocculant with the viscosity-average molecular weight of 1000 ten thousand under the stirring condition of 500rpm, continuously stirring for 20min, and standing for 2h to obtain a cationic polyacrylamide flocculant aqueous solution;
putting 200mL of shale gas fracturing flow-back fluid into a beaker, adding 0.6mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 1 into the beaker under the stirring condition of 200rpm, stirring for 20s, adding more than 0.4mL of the cationic polyacrylamide flocculant aqueous solution (in the application example, the dosage of the cationic polyacrylamide flocculant is 10mg/L based on the total volume of the shale gas fracturing flow-back fluid), adjusting the stirring speed to be 60rpm, continuing stirring for 20s, and standing and settling for 5 min.
The treatment effect data obtained in this application example are shown in table 1 below.
TABLE 1
Wherein, the suspended matter removal rate in table 1 is calculated according to the following formula:
the suspended matter content in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the method specified in the fracturing flowback fluid recovery and treatment method.
In the application example, the shale gas fracturing flow-back fluid before and after treatment is subjected to three times of suspended matter content determination respectively, and the average value of the results obtained by the three times of measurement is taken as the suspended matter content in the shale gas fracturing flow-back fluid before and after treatment respectively, and the specific data is shown in the following table 1-1.
TABLE 1-1
CaCO in Table 1 3 The scale inhibition rate is determined according to the method specified by SY/T5673-.
In the application example, CaCO is respectively carried out for three times on the treated shale gas fracturing flowback fluid 3 Determining the scale inhibition rate, and taking the average value of the results obtained by three times of measurements as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is shown in the following table 1-2.
Tables 1 to 2
| Temperature of | First experiment | Second experiment | Third experiment | Mean value of |
| 70℃ | 95％ | 93％ | 94％ | 94％ |
The sterilization rate in table 1 was calculated according to the following formula:
the total content of bacteria in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the fracturing flowback fluid recovery and treatment method is determined by the method specified in the methods for recovering and treating fracturing flowback fluid.
In the application example, the data of the total content of bacteria in the shale gas fracturing flowback fluid before and after treatment are shown in the following tables 1 to 3.
Tables 1 to 3
The corrosion rates in Table 1 were measured according to the method specified in SY/T5273-2014 Corrosion inhibitor Performance evaluation methods for oilfield produced Water.
In the application example, three corrosion rate determinations are respectively performed on the shale gas fracturing flow-back fluid before and after treatment, and the average value of the results obtained by the three determinations is respectively used as the corrosion rate of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 1 to 4 below.
Tables 1 to 4
The defoaming ratio in table 1 was calculated according to the following formula:
the foam volume in the formula was measured according to the following method: taking 100mL of shale gas fracturing flowback fluid to be tested, placing the shale gas fracturing flowback fluid into a high-speed stirrer container, stirring at 12000rpm for 1min at a high speed, then immediately pouring the liquid into a measuring cylinder, observing foam, and recording the volume of the foam.
In the application example, the foam volume of the shale gas fracturing flow-back fluid before and after treatment is respectively measured for three times, and the average value of the results of the three measurements is respectively used as the foam volume of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 1 to 5 below.
Tables 1 to 5
Application example 2
The application example provides a method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid composite treatment fluid provided in embodiment 2 comprises the following steps:
adding 200g of water into a 250mL beaker, slowly adding 1g of cationic polyacrylamide flocculant with the viscosity-average molecular weight of 800 ten thousand under the stirring condition of 500rpm, continuously stirring for 20min, and standing for 2h to obtain a cationic polyacrylamide flocculant aqueous solution;
putting 200mL of shale gas fracturing flow-back fluid into a beaker, adding 0.7mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 2 under the stirring condition of 200rpm, stirring for 20s, adding more than 0.5mL of the cationic polyacrylamide flocculant aqueous solution (in the application example, the dosage of the cationic polyacrylamide flocculant is 12.5mg/L based on the total volume of the shale gas fracturing flow-back fluid), adjusting the stirring speed to 60rpm, continuing stirring for 20s, and standing and settling for 5 min.
The treatment effect data obtained in this application example are shown in table 2 below.
TABLE 2
Wherein, the suspended matter removal rate in table 2 is calculated according to the following formula:
the suspended matter content in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the method specified in the fracturing flowback fluid recovery and treatment method.
In the application example, the shale gas fracturing flow-back fluid before and after treatment is subjected to three times of suspended matter content determination respectively, and the average value of the results obtained by the three times of measurement is taken as the suspended matter content in the shale gas fracturing flow-back fluid before and after treatment respectively, and the specific data is shown in the following table 2-1.
TABLE 2-1
CaCO in Table 2 3 The scale inhibition rate is determined according to the method specified by SY/T5673-.
In the application example, CaCO is respectively carried out for three times on the treated shale gas fracturing flowback fluid 3 Measuring the scale inhibition rate, and taking the average value of the results obtained by three measurements as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is shown in the following table 2-2.
Tables 2 to 2
| Temperature of | First experiment | Second experiment | Third experiment | Mean value of |
| 70℃ | 91％ | 91％ | 94％ | 92％ |
The sterilization rate in table 2 was calculated according to the following formula:
the total content of bacteria in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the method specified in the fracturing flowback fluid recovery and treatment method.
In the application example, the data of the total content of bacteria in the shale gas fracturing flowback fluid before and after treatment are shown in the following tables 2 to 3.
Tables 2 to 3
The corrosion rates in Table 2 were measured according to the method specified in SY/T5273-2014 Corrosion inhibitor Performance evaluation method for oilfield produced Water.
In the application example, three corrosion rate determinations are respectively performed on the shale gas fracturing flow-back fluid before and after treatment, and the average value of the results obtained by the three measurements is respectively used as the corrosion rate of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 2 to 4 below.
Tables 2 to 4
The defoaming ratio in table 2 was calculated according to the following formula:
the foam volume in the formula is measured according to the following method: taking 100mL of shale gas fracturing flowback fluid to be tested, placing the shale gas fracturing flowback fluid into a container of a high-speed stirrer, stirring at 12000rpm for 1min at high speed, immediately pouring the liquid into a measuring cylinder, observing foam, and recording the volume of the foam.
In the application example, the foam volume of the shale gas fracturing flow-back fluid before and after treatment is respectively measured for three times, and the average value of the results of the three measurements is respectively used as the foam volume of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 2 to 5 below.
Tables 2 to 5
Application example 3
The application example provides a method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid composite treatment fluid provided in embodiment 3 comprises the following steps:
adding 200g of water into a 250mL beaker, slowly adding 1g of cationic polyacrylamide flocculant with the viscosity-average molecular weight of 1200 ten thousand under the stirring condition of 500rpm, continuously stirring for 30min, and standing for 2h to obtain a cationic polyacrylamide flocculant aqueous solution;
putting 200mL of shale gas fracturing flow-back fluid into a beaker, adding 0.5mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 3 under the stirring condition of 200rpm, stirring for 20s, adding more than 0.3mL of the cationic polyacrylamide flocculant aqueous solution (in the application example, the dosage of the cationic polyacrylamide flocculant is 7.5mg/L based on the total volume of the shale gas fracturing flow-back fluid), adjusting the stirring speed to 60rpm, continuing stirring for 20s, and standing and settling for 5 min.
The treatment effect data obtained in this application example are shown in table 3 below.
TABLE 3
Wherein, the suspended matter removal rate in table 3 is calculated according to the following formula:
the suspended matter content in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the method specified in the fracturing flowback fluid recovery and treatment method.
In the application example, the shale gas fracturing flow-back fluid before and after treatment is subjected to three times of suspended matter content determination respectively, and the average value of the results obtained by the three times of measurement is taken as the suspended matter content in the shale gas fracturing flow-back fluid before and after treatment respectively, and the specific data is shown in the following table 3-1.
TABLE 3-1
CaCO in Table 3 3 The scale inhibition rate is measured according to the method specified by SY/T5673-And (4) determining.
In the application example, CaCO is respectively carried out for three times on the treated shale gas fracturing flowback fluid 3 Measuring the scale inhibition rate, and taking the average value of the results obtained by three measurements as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is shown in the following table 3-2.
TABLE 3-2
| Temperature of | First experiment | Second experiment | Third experiment | Mean value of |
| 70℃ | 95％ | 93％ | 92％ | 93％ |
The sterilization rate in table 3 was calculated according to the following formula:
the total content of bacteria in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the fracturing flowback fluid recovery and treatment method is determined by the method specified in the methods for recovering and treating fracturing flowback fluid.
In the application example, the data of the total content of bacteria in the shale gas fracturing flowback fluid before and after treatment are shown in the following tables 3 to 3.
Tables 3 to 3
The corrosion rates in Table 3 were measured according to the method specified in SY/T5273-2014 Corrosion inhibitor Performance evaluation method for oilfield produced Water.
In the application example, three corrosion rate determinations are respectively performed on the shale gas fracturing flow-back fluid before and after treatment, and the average value of the results obtained by the three determinations is respectively used as the corrosion rate of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 3 to 4 below.
Tables 3 to 4
The defoaming ratio in table 3 was calculated according to the following formula:
the foam volume in the formula is measured according to the following method: taking 100mL of shale gas fracturing flowback fluid to be tested, placing the shale gas fracturing flowback fluid into a container of a high-speed stirrer, stirring at 12000rpm for 1min at high speed, immediately pouring the liquid into a measuring cylinder, observing foam, and recording the volume of the foam.
In the application example, the foam volume of the shale gas fracturing flow-back fluid before and after treatment is respectively measured for three times, and the average value of the results of the three measurements is respectively used as the foam volume of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in the following tables 3 to 5.
Tables 3 to 5
Application example 4
The application example provides a method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid composite treatment fluid provided in embodiment 1 comprises the following steps:
adding 200g of water into a 250mL beaker, slowly adding 1g of cationic polyacrylamide flocculant with the viscosity-average molecular weight of 1000 ten thousand under the stirring condition of 500rpm, continuously stirring for 20min, and standing for 2h to obtain a cationic polyacrylamide flocculant aqueous solution;
adding 170g of water into a 250mL beaker, slowly adding 30g of modified diatomite (conventional substances, commercially available or prepared by a conventional method in a laboratory) under the stirring condition of 500rpm, and continuously stirring for 20min to obtain a modified diatomite suspension;
putting 200mL of shale gas fracturing flow-back fluid into a beaker, adding 0.5g of modified diatomite suspension (in the application example, the dosage of the modified diatomite is 375mg/L based on the total volume of the shale gas fracturing flow-back fluid) into the beaker under the stirring condition of 200rpm, adding 0.6mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 1 after uniformly mixing, stirring for 20s, adding more than 0.4mL of the cationic polyacrylamide flocculant aqueous solution (in the application example, the dosage of the cationic polyacrylamide flocculant is 10mg/L based on the total volume of the shale gas fracturing flow-back fluid), adjusting the stirring speed to 60rpm, continuously stirring for 20s, and standing and settling for 3 min.
The treatment effect data obtained in this application example are shown in table 4 below.
TABLE 4
Wherein, the suspended matter removal rate in table 4 is calculated according to the following formula:
the suspended matter content in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the fracturing flowback fluid recovery and treatment method is determined by the method specified in the methods for recovering and treating fracturing flowback fluid.
In the application example, the shale gas fracturing flow-back fluid before and after treatment is subjected to three times of suspended matter content determination, and the average value of the results obtained by the three times of measurement is taken as the suspended matter content in the shale gas fracturing flow-back fluid before and after treatment, and the specific data is shown in the following table 4-1.
TABLE 4-1
CaCO in Table 4 3 The scale inhibition rate is determined according to the method specified by SY/T5673-.
In the application example, CaCO is respectively carried out for three times on the treated shale gas fracturing flowback fluid 3 Measuring the scale inhibition rate, and taking the average value of the results obtained by three measurements as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is shown in the following table 4-2.
TABLE 4-2
| Temperature of | First experiment | Second experiment | Third experiment | Mean value of |
| 70℃ | 95％ | 95％ | 94％ | 95％ |
The sterilization rate in table 4 was calculated according to the following formula:
the total content of bacteria in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the fracturing flowback fluid recovery and treatment method is determined by the method specified in the methods for recovering and treating fracturing flowback fluid.
In the application example, the data of the total content of bacteria in the shale gas fracturing flowback fluid before and after treatment are shown in the following tables 4 to 3.
Tables 4 to 3
The corrosion rates in Table 4 were measured according to the method specified in SY/T5273-2014 Corrosion inhibitor Performance evaluation method for oilfield produced Water.
In the application example, three corrosion rate determinations are respectively performed on the shale gas fracturing flow-back fluid before and after treatment, and the average value of the results obtained by the three determinations is respectively used as the corrosion rate of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in the following tables 4 to 4.
Tables 4 to 4
The defoaming rate in table 4 was calculated according to the following formula:
the foam volume in the formula was measured according to the following method: taking 100mL of shale gas fracturing flowback fluid to be tested, placing the shale gas fracturing flowback fluid into a container of a high-speed stirrer, stirring at 12000rpm for 1min at high speed, immediately pouring the liquid into a measuring cylinder, observing foam, and recording the volume of the foam.
In the application example, the foam volume of the shale gas fracturing flow-back fluid before and after treatment is respectively measured for three times, and the average value of the results of the three measurements is respectively used as the foam volume of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 4 to 5 below.
Tables 4 to 5
Application example 5
The application example provides a method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid composite treatment fluid provided in embodiment 2 comprises the following steps:
adding 200g of water into a 250mL beaker, slowly adding 1g of cationic polyacrylamide flocculant with the viscosity-average molecular weight of 800 ten thousand under the stirring condition of 500rpm, continuously stirring for 20min, and standing for 2h to obtain a cationic polyacrylamide flocculant aqueous solution;
adding 160g of water into a 250mL beaker, slowly adding 40g of modified diatomite (conventional substances, commercially available or prepared by a conventional method in a laboratory) under the stirring condition of 500rpm, and continuously stirring for 20min to obtain a modified diatomite suspension;
putting 500mL of shale gas fracturing flow-back fluid into a beaker, adding 1g of modified diatomite suspension into the shale gas fracturing flow-back fluid under the stirring condition of 200rpm (in the application example, the dosage of the modified diatomite is 400mg/L based on the total volume of the shale gas fracturing flow-back fluid), adding 1.8mL of the composite treatment fluid for shale gas fracturing flow-back fluid provided in the embodiment 2 after uniformly mixing, stirring for 20s, adding more than 1.3mL of the cationic polyacrylamide flocculant aqueous solution (in the application example, the dosage of the cationic polyacrylamide flocculant is 13mg/L based on the total volume of the shale gas fracturing flow-back fluid), adjusting the stirring speed to 60rpm, continuing stirring for 20s, and standing and settling for 3 min.
The treatment effect data obtained in this application example are shown in table 5 below.
TABLE 5
Wherein the suspended matter removal rate in table 5 is calculated according to the following formula:
the suspended matter content in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the method specified in the fracturing flowback fluid recovery and treatment method.
In the application example, the shale gas fracturing flow-back fluid before and after treatment is subjected to three times of suspended matter content determination respectively, and the average value of the results obtained by the three times of measurement is taken as the suspended matter content in the shale gas fracturing flow-back fluid before and after treatment respectively, and the specific data is shown in the following table 5-1.
TABLE 5-1
CaCO in Table 5 3 The scale inhibition rate is determined according to the method specified by SY/T5673-.
In the application example, CaCO is respectively carried out for three times on the treated shale gas fracturing flowback fluid 3 Measuring the scale inhibition rate, and taking three measurementsTaking the average value of the obtained results as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is shown in the following table 5-2.
TABLE 5-2
| Temperature of | First experiment | Second experiment | Third experiment | Mean value of |
| 70℃ | 94％ | 94％ | 95％ | 94％ |
The sterilization rate in table 5 was calculated according to the following formula:
the total content of bacteria in the formula is according to NB/T14002.3-2015 part 3 of shale gas reservoir reconstruction: the method specified in the fracturing flowback fluid recovery and treatment method.
In the application example, the data of the total content of bacteria in the shale gas fracturing flowback fluid before and after treatment are shown in the following tables 5 to 3.
Tables 5 to 3
The corrosion rates in Table 5 were measured according to the method specified in SY/T5273-2014 Corrosion inhibitor Performance evaluation method for oilfield produced Water.
In the application example, three corrosion rate determinations are respectively performed on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is respectively used as the corrosion rate of the shale gas fracturing flowback fluid before and after treatment, and the specific data are shown in the following tables 5 to 4.
Tables 5 to 4
The defoaming ratio in table 5 was calculated according to the following formula:
the foam volume in the formula was measured according to the following method: taking 100mL of shale gas fracturing flowback fluid to be tested, placing the shale gas fracturing flowback fluid into a container of a high-speed stirrer, stirring at 12000rpm for 1min at high speed, immediately pouring the liquid into a measuring cylinder, observing foam, and recording the volume of the foam.
In the application example, the foam volume determination is performed three times on the shale gas fracturing flow-back fluid before and after treatment, and the average value of the results obtained by the three times of measurement is taken as the foam volume of the shale gas fracturing flow-back fluid before and after treatment, and the specific data are shown in tables 5 to 5 below.
Tables 5 to 5
In summary, it can be seen by combining the effect data in tables 1 to 5 above that the composite treatment fluid for shale gas fracturing flowback fluid provided by the embodiment of the present invention has multiple functions of scale inhibition, corrosion inhibition, flocculation, sterilization, defoaming, and the like, and has a good application prospect in shale gas fracturing flowback fluid treatment.
The above description is only exemplary of the invention and should not be taken as limiting the scope of the invention, so that the invention is intended to cover all modifications and equivalents of the embodiments described herein. In addition, the technical features and the technical inventions of the present invention, the technical features and the technical inventions, and the technical inventions can be freely combined and used.
Claims (21)
1. The shale gas fracturing flow-back fluid composite treatment fluid comprises 3-6% of neutral phosphonate component, 5-12% of inorganic flocculation component, 1.5-3% of sterilization component, 2-5% of water-soluble defoaming component and the balance of water, wherein the content of the sterilization component and the content of the water-soluble defoaming component are respectively calculated according to the content of effective components in the sterilization component and the water-soluble defoaming component, and the total weight of the shale gas fracturing flow-back fluid composite treatment fluid is 100%;
the inorganic flocculating component is free of iron ions and sulfate ions.
2. The shale gas fracturing flow-back fluid composite treating fluid of claim 1, wherein the neutral phosphonate component comprises one or a combination of several of tetrasodium amino trimethylene phosphonate, potassium hydroxy ethylidene diphosphonate, pentasodium ethylene diamine tetra methylene phosphonate, pentasodium diethylene triamine pentamethylene phosphonate, heptasodium diethylene triamine pentamethylene phosphonate, and potassium hexamethylene diamine tetra methylene phosphonate.
3. The shale gas fracturing flow-back fluid composite treatment fluid of claim 1 or 2, wherein the inorganic flocculating component comprises one or a combination of polyaluminium chloride, polyaluminium chloride and aluminum magnesium polysilicate.
4. The shale gas fracturing flowback fluid composite treatment fluid of claim 1 or 2, wherein the bactericidal component comprises one or a combination of several of an aldehyde bactericide, a quaternary ammonium salt bactericide and an isothiazolinone bactericide.
5. The composite treatment fluid for shale gas fracturing flowback fluid of claim 4, wherein the aldehyde bactericide comprises one or more of glutaraldehyde, formaldehyde and acrolein.
6. The composite treatment fluid for shale gas fracturing flow-back fluid as claimed in claim 5, wherein the aldehyde bactericide is glutaraldehyde.
7. The shale gas fracturing flowback fluid composite treatment fluid of claim 4, wherein the quaternary ammonium salt bactericide comprises one or a combination of tetradecyl dimethyl benzyl ammonium chloride, dodecyl trimethyl ammonium chloride, dodecyl dimethyl benzyl ammonium bromide and tetramethyl ammonium chloride.
8. The shale gas fracturing flowback fluid composite treatment fluid of claim 7, wherein the quaternary ammonium salt bactericide is dodecyl dimethyl benzyl ammonium chloride or tetramethyl ammonium chloride.
9. The shale gas fracturing flowback fluid composite treatment fluid of claim 4, wherein the isothiazolinone biocide comprises methylisothiazolinone and/or methylchloroisothiazolinone.
10. The shale gas fracturing flowback fluid composite treating fluid of claim 9, wherein the isothiazolinone bactericide is methylisothiazolinone.
11. The shale gas fracturing flow-back fluid composite treatment fluid of claim 1 or 2, wherein the water-soluble defoaming component comprises one or more of a polyether defoamer and a silicone defoamer.
12. The preparation method of the shale gas fracturing flow-back fluid composite treatment fluid of any one of claims 1 to 11, wherein the preparation method comprises the following steps:
adding a water-soluble defoaming component into water under the condition of stirring, adding a solid component in raw materials for preparing the shale gas fracturing flow-back fluid composite treatment fluid after uniformly stirring, uniformly stirring to form a turbid liquid, adding a liquid component in the raw materials into the turbid liquid, and uniformly stirring to obtain the turbid liquid, namely the shale gas fracturing flow-back fluid composite treatment fluid.
13. Use of the shale gas fracturing flowback fluid composite treatment fluid of any of claims 1 to 11 in the treatment of shale gas fracturing flowback fluid.
14. A method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid utilizes the composite treating fluid of any one of claims 1 to 11, and comprises the following steps:
adding the shale gas fracturing flow-back fluid composite treatment fluid of any one of claims 1 to 11 into the shale gas fracturing flow-back fluid, uniformly mixing, adding a flocculant solution, uniformly mixing, and settling.
15. The method according to claim 14, wherein the shale gas fracturing flow-back fluid composite treatment fluid is used in an amount of 0.1-0.8% and the flocculant is used in an amount of 5-20mg/L, based on the total volume of the shale gas fracturing flow-back fluid.
16. A process according to claim 14 or 15, wherein the flocculating agent is a cationic polyacrylamide.
17. The method of claim 16, wherein the cationic polyacrylamide has a viscosity average molecular weight of 150 to 2000 ten thousand.
18. A method for treating shale gas fracturing flowback fluid, wherein the method for treating shale gas fracturing flowback fluid utilizes the composite treating fluid of any one of claims 1 to 11, and comprises the following steps:
adding modified diatomite into the shale gas fracturing flow-back fluid, uniformly mixing, then adding the shale gas fracturing flow-back fluid composite treatment fluid of any one of claims 1-11, uniformly mixing, then adding a flocculant solution, uniformly mixing, and then settling.
19. The method as claimed in claim 18, wherein the amount of the modified diatomite is 100-500mg/L, the amount of the shale gas fracturing flow-back fluid composite treatment fluid is 0.1-0.8%, and the amount of the flocculant is 5-20mg/L, based on the total volume of the shale gas fracturing flow-back fluid.
20. A process according to claim 18 or 19, wherein the flocculating agent is a cationic polyacrylamide.
21. The method of claim 20, wherein the cationic polyacrylamide has a viscosity average molecular weight of 150 to 2000 ten thousand.
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| CN110482754A (en) * | 2018-05-15 | 2019-11-22 | 中国石油天然气股份有限公司 | Shale gas fracturing outlet liquid processing method and processing unit |
| CN111423011A (en) * | 2020-03-23 | 2020-07-17 | 中国石油天然气集团有限公司 | Shale gas fracturing flowback fluid treatment and reuse method |
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| CN110270309A (en) * | 2019-07-25 | 2019-09-24 | 西南石油大学 | A kind of shale gas fracturing outlet liquid water treatment absorbent preparation method and application |
| CN111423011A (en) * | 2020-03-23 | 2020-07-17 | 中国石油天然气集团有限公司 | Shale gas fracturing flowback fluid treatment and reuse method |
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