CN115124159B - Shale gas fracturing flow-back fluid composite treatment fluid and preparation method and application thereof - Google Patents
Shale gas fracturing flow-back fluid composite treatment fluid and preparation method and application thereof Download PDFInfo
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- CN115124159B CN115124159B CN202110330723.8A CN202110330723A CN115124159B CN 115124159 B CN115124159 B CN 115124159B CN 202110330723 A CN202110330723 A CN 202110330723A CN 115124159 B CN115124159 B CN 115124159B
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- 239000012530 fluid Substances 0.000 title claims abstract description 252
- 239000002131 composite material Substances 0.000 title claims abstract description 72
- 238000002360 preparation method Methods 0.000 title claims abstract description 12
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 24
- 238000005189 flocculation Methods 0.000 claims abstract description 22
- 230000016615 flocculation Effects 0.000 claims abstract description 22
- 230000001954 sterilising effect Effects 0.000 claims abstract description 21
- 238000004659 sterilization and disinfection Methods 0.000 claims abstract description 21
- 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 12
- -1 iron ions Chemical class 0.000 claims abstract description 12
- 230000007935 neutral effect Effects 0.000 claims abstract description 12
- 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
- 238000000034 method Methods 0.000 claims description 92
- 238000003756 stirring Methods 0.000 claims description 57
- 125000002091 cationic group Chemical group 0.000 claims description 29
- 229920002401 polyacrylamide Polymers 0.000 claims description 29
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N Silicium dioxide Chemical class O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 claims description 20
- 230000000844 anti-bacterial effect Effects 0.000 claims description 19
- 239000003899 bactericide agent Substances 0.000 claims description 16
- 239000000725 suspension Substances 0.000 claims description 16
- 239000007788 liquid Substances 0.000 claims description 11
- 238000002156 mixing Methods 0.000 claims description 9
- 239000002994 raw material Substances 0.000 claims description 7
- 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
- 150000001875 compounds Chemical class 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
- HGINCPLSRVDWNT-UHFFFAOYSA-N Acrolein Chemical compound C=CC=O HGINCPLSRVDWNT-UHFFFAOYSA-N 0.000 claims description 4
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 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
- 229920000570 polyether Polymers 0.000 claims description 4
- 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 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
- 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 3
- 229940100484 5-chloro-2-methyl-4-isothiazolin-3-one Drugs 0.000 claims description 2
- IOOLLUXHARIZLZ-UHFFFAOYSA-N [Na].NC1CCOP(=O)O1 Chemical compound [Na].NC1CCOP(=O)O1 IOOLLUXHARIZLZ-UHFFFAOYSA-N 0.000 claims description 2
- SNAAJJQQZSMGQD-UHFFFAOYSA-N aluminum magnesium Chemical compound [Mg].[Al] SNAAJJQQZSMGQD-UHFFFAOYSA-N 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
- 230000003311 flocculating effect Effects 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
- 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
- 230000000855 fungicidal effect Effects 0.000 claims 1
- 239000000417 fungicide Substances 0.000 claims 1
- WSFSSNUMVMOOMR-NJFSPNSNSA-N methanone Chemical compound O=[14CH2] WSFSSNUMVMOOMR-NJFSPNSNSA-N 0.000 claims 1
- 230000007797 corrosion Effects 0.000 abstract description 26
- 238000005260 corrosion Methods 0.000 abstract description 26
- 230000005764 inhibitory process Effects 0.000 abstract description 26
- 239000007789 gas Substances 0.000 description 165
- 239000006260 foam Substances 0.000 description 27
- 238000005259 measurement Methods 0.000 description 25
- 239000007864 aqueous solution Substances 0.000 description 15
- 238000002474 experimental method Methods 0.000 description 15
- 230000001580 bacterial effect Effects 0.000 description 11
- 238000012986 modification Methods 0.000 description 11
- 230000004048 modification Effects 0.000 description 11
- 238000011084 recovery Methods 0.000 description 10
- 230000000694 effects Effects 0.000 description 9
- 238000012545 processing Methods 0.000 description 9
- 239000002455 scale inhibitor Substances 0.000 description 8
- 239000000243 solution Substances 0.000 description 8
- 239000000203 mixture Substances 0.000 description 7
- 239000003112 inhibitor Substances 0.000 description 6
- 239000002518 antifoaming agent Substances 0.000 description 5
- 239000013530 defoamer Substances 0.000 description 5
- 238000011156 evaluation Methods 0.000 description 5
- 229920002545 silicone oil Polymers 0.000 description 5
- 238000012360 testing method Methods 0.000 description 5
- 239000002699 waste material Substances 0.000 description 5
- 241000894006 Bacteria Species 0.000 description 4
- 239000003814 drug Substances 0.000 description 4
- 229910021645 metal ion Inorganic materials 0.000 description 4
- 238000003672 processing method Methods 0.000 description 4
- 238000004062 sedimentation Methods 0.000 description 4
- WSFSSNUMVMOOMR-UHFFFAOYSA-N Formaldehyde Chemical compound O=C WSFSSNUMVMOOMR-UHFFFAOYSA-N 0.000 description 3
- 239000003995 emulsifying agent Substances 0.000 description 3
- 230000008569 process Effects 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
- 230000002776 aggregation Effects 0.000 description 2
- 238000004220 aggregation Methods 0.000 description 2
- AZDRQVAHHNSJOQ-UHFFFAOYSA-N alumane Chemical class [AlH3] AZDRQVAHHNSJOQ-UHFFFAOYSA-N 0.000 description 2
- 239000003638 chemical reducing agent Substances 0.000 description 2
- 239000003795 chemical substances by application 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
- 239000008394 flocculating agent Substances 0.000 description 2
- 230000005484 gravity Effects 0.000 description 2
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 2
- 239000000463 material Substances 0.000 description 2
- 230000003647 oxidation Effects 0.000 description 2
- 238000007254 oxidation reaction Methods 0.000 description 2
- 238000001556 precipitation Methods 0.000 description 2
- 239000013049 sediment Substances 0.000 description 2
- 239000000126 substance Substances 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
- JLVVSXFLKOJNIY-UHFFFAOYSA-N Magnesium ion Chemical compound [Mg+2] JLVVSXFLKOJNIY-UHFFFAOYSA-N 0.000 description 1
- 241000186359 Mycobacterium Species 0.000 description 1
- 229910004298 SiO 2 Inorganic materials 0.000 description 1
- 239000002253 acid Substances 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
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 230000000903 blocking effect Effects 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
- 238000006243 chemical reaction Methods 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
- 239000007822 coupling agent Substances 0.000 description 1
- 239000003431 cross linking reagent Substances 0.000 description 1
- 230000007547 defect Effects 0.000 description 1
- 230000018044 dehydration Effects 0.000 description 1
- 238000006297 dehydration reaction Methods 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 229940090960 diethylenetriamine pentamethylene phosphonic acid Drugs 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
- 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
- 238000005868 electrolysis reaction Methods 0.000 description 1
- 238000005187 foaming Methods 0.000 description 1
- 238000010528 free radical solution polymerization reaction 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
- HCWCAKKEBCNQJP-UHFFFAOYSA-N magnesium orthosilicate Chemical compound [Mg+2].[Mg+2].[O-][Si]([O-])([O-])[O-] HCWCAKKEBCNQJP-UHFFFAOYSA-N 0.000 description 1
- 239000000391 magnesium silicate Substances 0.000 description 1
- 229910052919 magnesium silicate Inorganic materials 0.000 description 1
- 235000019792 magnesium silicate Nutrition 0.000 description 1
- 230000000813 microbial effect Effects 0.000 description 1
- 244000005700 microbiome Species 0.000 description 1
- 239000011259 mixed solution Substances 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
- 239000001301 oxygen Substances 0.000 description 1
- 229910052760 oxygen Inorganic materials 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
- 229920001282 polysaccharide Polymers 0.000 description 1
- 239000005017 polysaccharide Substances 0.000 description 1
- 235000019353 potassium silicate Nutrition 0.000 description 1
- 238000004064 recycling Methods 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 239000010865 sewage Substances 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
- 238000006467 substitution reaction Methods 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
- XDLNRRRJZOJTRW-UHFFFAOYSA-N thiohypochlorous acid Chemical compound ClS XDLNRRRJZOJTRW-UHFFFAOYSA-N 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 flow-back fluid composite treatment fluid and a preparation method and application thereof, 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%, 3-6% of neutral phosphonate components, 5-12% of inorganic flocculation components, 1.5-3% of sterilization components, 2-5% of water-soluble defoaming components and the balance of water, wherein the contents of the sterilization components and the water-soluble defoaming components are calculated according to the contents of effective components in the sterilization components and the water-soluble defoaming components respectively; the inorganic flocculation component is free of iron ions and sulfate ions. The shale gas fracturing flowback fluid composite treatment 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 shale gas fracturing flowback fluid treatment.
Description
Technical Field
The invention relates to shale gas fracturing flowback fluid composite treatment fluid and a preparation method and application thereof, and belongs to the technical field of sewage treatment.
Background
Shale gas development requires large water quantity, and the produced fracturing flowback fluid is more and needs to be treated. Currently, there are numerous techniques related to treatment of frac flowback fluid in the prior art, such as: chinese patent CN110615514a discloses an aluminum salt microorganism composite flocculant for treating shale gas drilling wastewater, the preparation method of the flocculant comprises: firstly adding PDMDAAC (dimethyl diallyl ammonium chloride homopolymer) into aluminum sulfate solution to obtain PAS-PDM solution, then adding polysaccharide extracted from mycobacterium into the mixed solution, stirring to obtain stable aluminum salt microbial composite flocculant, and compared with the conventional coagulant used in the field, the COD removal rate can be increased by 24.10-12.60%, and the chromaticity removal rate can be increased by 50-10%.
Chinese patent CN102786186a discloses a treatment method for shale gas fracturing flow-back waste liquid, 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 reach the standard and be discharged and recycled, but the treatment process of the treatment method is complicated.
Chinese patent CN103043831a discloses a method for treating waste liquid from fracturing operation of a land shale gas well, which comprises: 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 perform oxidation and viscosity reduction, then readjusting the pH value of the waste liquid to 7.0-8.5, and finally, circularly utilizing the waste water to prepare fracturing fluid or reinjection stratum through flocculation sedimentation and filtration.
Chinese patent CN106145296A discloses a preparation method of a composite flocculant for recycling pretreatment of fracturing flowback fluid, wherein the raw materials of the flocculant comprise high-viscosity biological flocculant, polyaluminium chloride, anhydrous citric acid and tap water, and the flocculant solves the problem that the existing shale gas fracturing flowback fluid flocculation treatment agent is difficult to degrade, can cause secondary pollution or can introduce high-valence metal ions to greatly influence the performance of fracturing fluid.
Chinese patent CN104292386A discloses a composite flocculant for flocculating treatment of fracturing flowback fluid and a preparation method thereof, wherein the raw material composition of the flocculant comprises water glass, a coupling agent, an acrylamide monomer, a cationic monomer, a crosslinking agent and an initiator, the composite flocculant is prepared by adopting an aqueous solution polymerization method, and the flocculant is SiO 2 -cationic polyacrylamide composite flocculant.
The fracturing flow-back fluid treatment medicaments are mainly combined application of various flocculation treatment medicaments, have single function, do not have the functions of one agent and multiple effects of scale inhibition, corrosion inhibition, flocculation, sterilization and defoaming.
Therefore, the novel shale gas fracturing flow-back fluid composite treatment fluid, the preparation method and the application thereof have become technical problems to be solved in the field.
Disclosure of Invention
In order to solve the defects, the invention aims to provide a shale gas fracturing flow-back fluid composite treatment fluid.
The invention also aims at providing a preparation method of the shale gas fracturing flow-back fluid composite treatment fluid.
The invention also aims to provide the application of the shale gas fracturing flow-back fluid composite treatment fluid in treating shale gas fracturing flow-back fluid.
The invention also aims to provide a treatment method of the shale gas fracturing flowback fluid, wherein the treatment method utilizes the shale gas fracturing flowback 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 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 sterilization component and the water-soluble defoaming component are contained in the amounts of the sterilization component and the water-soluble defoaming component, respectively, based on the total weight of the shale gas fracturing flow-back fluid composite treatment fluid as 100%;
the inorganic flocculation component is free of iron ions and sulfate ions.
Neutral in the present invention means that the pH value of the phosphonate stock solution or phosphonate aqueous solution (mass concentration is 6%) is 6-8.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the neutral phosphonate component comprises one or a combination of more of tetra sodium aminotrimethylene phosphonate, potassium hydroxyethylidene diphosphonate, pentasodium ethylenediamine tetramethylene phosphonate, pentasodium diethylenetriamine pentamethylene phosphonate, heptasodium diethylenetriamine pentamethylene phosphonate and potassium hexamethylenediamine tetramethylene phosphonate.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the inorganic flocculation component comprises one or a combination of a plurality of polyaluminium chloride, polyaluminium sulfatochloride and polyaluminium magnesium silicate.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the sterilization component comprises one or a combination of more of aldehyde bactericides, quaternary ammonium salt bactericides and isothiazolinone bactericides.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the aldehyde bactericide comprises one or a combination of more of glutaraldehyde, formaldehyde and acrolein.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the aldehyde bactericide is glutaraldehyde.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the quaternary ammonium salt bactericide comprises one or a combination of more of tetradecyldimethylbenzyl ammonium chloride, dodecyl trimethyl ammonium chloride, dodecyl dimethylbenzyl ammonium bromide and tetramethyl ammonium chloride.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the quaternary ammonium salt bactericide is dodecyl dimethyl benzyl ammonium chloride or tetramethyl ammonium chloride.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the isothiazolinone bactericide comprises methyl isothiazolinone and/or methyl chloroisothiazolinone.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the isothiazolinone bactericide is methyl isothiazolinone.
As a specific embodiment of the shale gas fracturing flow-back fluid composite treatment fluid, the water-soluble defoaming component comprises one or a combination of more than one of polyether defoamer and silicone defoamer.
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 is avoided from blocking pipelines, equipment, filters and the like in the subsequent water treatment process; the synergistic effect of 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 is excellent; the neutral phosphonate component is used as a scale inhibition component, so that the dissolution of high-valence metal ion sediment (insoluble carbonate and/or insoluble hydroxide) and/or colloid which are already precipitated in the shale gas fracturing flowback fluid by an acid scale inhibitor can be avoided, the hardness of the shale gas fracturing flowback fluid is increased, and the generation of precipitation by the reaction of an alkaline scale inhibitor and a flocculation component in the shale gas fracturing flowback fluid composite treatment fluid can be avoided; meanwhile, the neutral phosphonate can also play a certain role in corrosion resistance;
the inorganic flocculation component can flocculate and settle shale gas fracturing flowback 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 in the invention can avoid the influence of the iron ions on the performance of the resistance reducing agent when shale gas fracturing flowback fluid is recycled, can also avoid the problem of blackout of the flowback fluid caused by ferrous sulfide generated by combining hydrogen sulfide generated by sulfate reducing bacteria with the iron ions, and can also avoid the introduction of sulfate to provide a necessary environment for the growth of the sulfate reducing bacteria;
the bactericidal component has broad-spectrum bactericidal effect and can inhibit bacterial growth within a certain time.
The water-soluble defoaming component can avoid the foaming problem of shale gas fracturing flowback fluid caused by the fact that the shale gas fracturing flowback fluid contains a surfactant, and the problems of COD increase, demulsification and layering of medicaments and the like caused by the fact that the conventional organic silicone oil emulsion defoaming agent (oil phase containing silicone oil and the like, precipitated silica, emulsifying agent and the like) is used can not be caused by the fact that one or a combination of a polyether defoaming agent and a silicone defoaming agent is used 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 stirring condition, stirring uniformly, adding a solid component in a raw material used for preparing the shale gas fracturing flow-back fluid compound treatment fluid, stirring uniformly to form a suspension, adding a liquid component in the raw material into the suspension, and stirring uniformly to obtain the suspension, namely the shale gas fracturing flow-back fluid compound treatment fluid.
In still another aspect, the invention further provides application of the shale gas fracturing flow-back fluid composite treatment fluid in treatment of shale gas fracturing flow-back fluid.
In still another aspect, the present invention further provides a method for processing shale gas fracturing flowback fluid, where the processing method uses the shale gas fracturing flowback fluid composite processing fluid, and the processing method includes:
adding the shale gas fracturing flowback fluid composite treatment fluid into the shale gas fracturing flowback fluid, uniformly mixing, adding a flocculant solution, uniformly mixing, and settling.
As a specific implementation mode of the method, the dosage of the composite treatment liquid of the shale gas fracturing flowback fluid is 0.1-0.8% and the dosage of the flocculating agent is 5-20mg/L based on the total volume of the shale gas fracturing flowback fluid.
As a specific embodiment of the above method of the present invention, wherein the flocculant is cationic polyacrylamide.
As a specific embodiment of the above method of the present invention, wherein the cationic polyacrylamide has a viscosity average molecular weight of 150 to 2000 tens of thousands.
In the treatment method, the shale gas fracturing flowback fluid composite treatment fluid is added into the shale gas fracturing flowback fluid to flocculate, and then flocculant solution (such as cationic polyacrylamide solution) is added to enlarge the aggregation of the flocs and the flocs are settled by gravity.
In still another aspect, the present invention further provides a method for processing shale gas fracturing flowback fluid, where the processing method uses the shale gas fracturing flowback fluid composite processing fluid, and the processing method includes:
adding modified diatomite into the shale gas fracturing flowback fluid, uniformly mixing, adding the shale gas fracturing flowback fluid composite treatment fluid, uniformly mixing, adding a flocculant solution, uniformly mixing, and settling.
As a specific implementation mode of the method, the dosage of the modified diatomite is 100-500mg/L, the dosage of the shale gas fracturing flow-back fluid composite treatment fluid is 0.1-0.8%, and the dosage of the flocculant is 5-20mg/L based on the total volume of the shale gas fracturing flow-back fluid.
As a specific embodiment of the above method of the present invention, wherein the flocculant is cationic polyacrylamide.
As a specific embodiment of the above method of the present invention, wherein the cationic polyacrylamide has a viscosity average molecular weight of 150 to 2000 tens of thousands.
In the treatment method, firstly, modified diatomite is added into shale gas fracturing flowback fluid for flocculation, then the shale gas fracturing flowback fluid composite treatment fluid is added for flocculation, and finally flocculant solution (such as cationic polyacrylamide solution) is added to enlarge the aggregation of flocs and the flocs are precipitated by gravity.
The modified diatomite is added during treatment of shale gas fracturing flowback fluid, so that the settling time of the flocculated and settled sludge is faster, and the dehydration property is better.
Compared with the prior art, the technical scheme of the invention can achieve the following effects:
1) The shale gas fracturing flow-back fluid composite treatment fluid provided by the invention simultaneously comprises a neutral phosphonate component, an inorganic flocculation component free of iron ions and sulfate ions, a sterilization component and a water-soluble defoaming component, so that 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 added independently can be avoided;
2) The composite treatment liquid for the shale gas fracturing flowback fluid provided by the invention does not contain iron ions, so that the influence of the iron ions on the resistance reducing performance of the resistance reducing agent during the return of the shale gas fracturing flowback fluid is avoided, and the problem of water blackening caused by the combination of the iron ions and hydrogen sulfide generated by sulfate reducing bacteria to generate ferrous sulfide is also avoided;
3) The shale gas fracturing flowback fluid compound treatment fluid provided by the invention does not contain sulfate (sulfate ions), so that a large number of breeding of sulfate reducing bacteria is avoided;
4) The neutral phosphonate component is used as the scale inhibition component, so that high-valence metal ion sediment and/or colloid which are already precipitated in the shale gas fracturing flowback fluid are not dissolved, and further the increase of the hardness of the shale gas fracturing flowback fluid can be avoided;
5) The defoaming component adopted by the composite treatment fluid for the shale gas fracturing flow-back fluid does not contain oil phase such as silicone oil, precipitated silica, emulsifying agent 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 shale gas fracturing flow-back fluid generates foam in subsequent industrial application after treatment, and can not cause the problems of COD (chemical oxygen demand) increase, medicament demulsification layering and the like caused by using the conventional silicone oil emulsion defoaming agent (the oil phase such as silicone oil, the substances such as precipitated silica and emulsifying agent and the like);
6) In conclusion, the shale gas fracturing flowback fluid composite treatment 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 shale gas fracturing flowback fluid treatment.
Detailed Description
In order to make the technical features, objects and advantageous effects of the present invention more clearly understood, the technical aspects of the present invention will now be described in detail with reference to the following specific examples, but should not be construed as limiting the scope of the present invention.
In the following examples, the operations were carried out under conventional conditions or conditions recommended by the manufacturer, and the raw materials used were conventional products commercially available without specifying the manufacturer and the specification.
Example 1
The embodiment provides a shale gas fracturing flow-back fluid composite treatment fluid, which is prepared by a method comprising the following steps:
777g of water is added into a 1000mL beaker, then 28g of silicone defoamer is added under the stirring condition of 300rpm, and the mixture is stirred for 5min; then, under the stirring condition of 300rpm, sequentially adding 35g of diethylenetriamine penta-methylene phosphonic acid pentasodium and 100g of polyaluminum chloride, and stirring 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 flow-back fluid composite treatment fluid.
Example 2
The embodiment provides a shale gas fracturing flow-back fluid composite treatment fluid, which is prepared by a method comprising the following steps:
755g of water is added into a 1000mL beaker, and then 35g of silicone defoamer is added under the stirring condition of 300rpm, and the mixture is stirred for 5min; then 45g of pentasodium ethylenediamine tetramethylene phosphonate and 110g of polyaluminum sulfanyl chloride are added in turn under the stirring condition of 300rpm, and the mixture is stirred 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 continuing stirring for 10min to obtain uniform suspension, namely the shale gas fracturing flow-back fluid composite treatment fluid.
Example 3
The embodiment provides a shale gas fracturing flow-back fluid composite treatment fluid, which is prepared by a method comprising the following steps:
477g of water is added into a 1000mL beaker, 48g of polyether defoamer is added under the stirring condition of 300rpm, and the mixture is stirred for 5min; then adding 55g of potassium hydroxyethylidene diphosphonate and 120g of magnesium aluminum polysilicate in turn under the stirring condition of 300rpm, and stirring for 15min to form uniform suspension; and then adding 300g of 9.5% methyl isothiazolinone aqueous solution under the stirring condition of 300rpm, and continuing stirring for 10min to obtain uniform suspension, namely the shale gas fracturing flow-back fluid composite treatment fluid.
Application example 1
The application example provides a treatment method of shale gas fracturing flowback fluid, wherein the treatment method utilizes the shale gas fracturing flowback fluid composite treatment fluid provided in the embodiment 1, and the treatment method comprises the following steps:
200g of water is added into a 250mL beaker, 1g of cationic polyacrylamide flocculant with viscosity average molecular weight of 1000 ten thousand is slowly added under the stirring condition of 500rpm, stirring is continued for 20min, and standing is carried out for 2h, so as to obtain cationic polyacrylamide flocculant aqueous solution;
200mL of shale gas fracturing flow-back fluid is placed in a beaker, 0.6mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 1 is added into the beaker under the stirring condition of 200rpm, the stirring is carried out for 20s, 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) is added, the stirring speed is adjusted to be 60rpm, the stirring is continued for 20s, and the mixture is kept stand and settled for 5min.
The processing 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 content of suspended matters in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In the application example, three suspended matter content determinations are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three determinations is taken as the suspended matter content in the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following table 1-1.
TABLE 1-1
CaCO in Table 1 3 The scale inhibition rate is measured according to the method specified in SY/T5673-2020 general technical Condition for Scale inhibitor for oilfield.
In the application example, caCO (CaCO) is respectively carried out three times on the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is measured, and the average value of the results obtained by three measurements is taken as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate and specific data are shown in the following tables 1-2.
TABLE 1-2
| Temperature (temperature) | First experiment | Second experiment | Third experiment | Average value of |
| 70℃ | 95％ | 93％ | 94％ | 94％ |
The sterilization rate in table 1 is calculated according to the following formula:
the total bacterial content in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In this application example, the total bacterial content data in the pre-and post-treatment shale gas fracturing flowback fluid are shown in tables 1-3 below.
Tables 1 to 3
The corrosion rates in Table 1 were measured according to the method prescribed in SY/T5273-2014 corrosion inhibitor Performance evaluation method for oilfield produced water.
In the application example, three corrosion rate measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the corrosion rate of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 1-4.
Tables 1 to 4
The defoaming rate in table 1 is calculated according to the following formula:
the test of the foam volume in the formula was performed as follows: 100mL of shale gas fracturing flow-back fluid to be tested is taken and placed in a high-speed stirrer container, stirred at a high speed at 12000rpm for 1min, then immediately poured into a measuring cylinder to observe foam, and the foam volume is recorded.
In the application example, three foam volume measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the foam volume of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 1-5.
Tables 1 to 5
Application example 2
The application example provides a treatment method of shale gas fracturing flowback fluid, wherein the treatment method utilizes the shale gas fracturing flowback fluid composite treatment fluid provided in the embodiment 2, and the treatment method comprises the following steps:
200g of water is added into a 250mL beaker, 1g of cationic polyacrylamide flocculant with the viscosity average molecular weight of 800 ten thousand is slowly added under the stirring condition of 500rpm, stirring is continued for 20min, and standing is carried out for 2h, so that a cationic polyacrylamide flocculant aqueous solution is obtained;
200mL of shale gas fracturing flow-back fluid is placed in a beaker, 0.7mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 2 is added under the stirring condition of 200rpm, stirring is carried out for 20s, then 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) is added, the stirring speed is adjusted to be 60rpm, stirring is continued for 20s, and standing and sedimentation are carried out for 5min.
The processing 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 content of suspended matters in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In the application example, three suspended matter content determinations are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three determinations is taken as the suspended matter content in the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following table 2-1.
TABLE 2-1
CaCO in Table 2 3 The scale inhibition rate is measured according to the method specified in SY/T5673-2020 general technical Condition for Scale inhibitor for oilfield.
In the application example, caCO (CaCO) is respectively carried out three times on the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is measured, and the average value of the results obtained by three measurements is taken as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate and specific data are shown in the following tables 2-2.
TABLE 2-2
| Temperature (temperature) | First experiment | Second experiment | Third experiment | Average value of |
| 70℃ | 91％ | 91％ | 94％ | 92％ |
The sterilization rate in table 2 was calculated according to the following formula:
the total bacterial content in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In this application example, the total bacterial content data in the pre-and post-treatment shale gas fracturing flowback fluid are shown in tables 2-3 below.
Tables 2 to 3
The corrosion rates in Table 2 were measured according to the method prescribed in SY/T5273-2014 corrosion inhibitor Performance evaluation method for oilfield produced water.
In the application example, three corrosion rate measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the corrosion rate of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 2-4.
Tables 2 to 4
The defoaming rate in table 2 was calculated according to the following formula:
the test of the foam volume in the formula was performed as follows: 100mL of shale gas fracturing flow-back fluid to be tested is taken and placed in a high-speed stirrer container, stirred at a high speed at 12000rpm for 1min, then immediately poured into a measuring cylinder to observe foam, and the foam volume is recorded.
In the application example, three foam volume measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the foam volume of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 2-5.
Tables 2 to 5
Application example 3
The application example provides a treatment method of shale gas fracturing flowback fluid, wherein the treatment method utilizes the shale gas fracturing flowback fluid composite treatment fluid provided in the embodiment 3, and the treatment method comprises the following steps:
200g of water is added into a 250mL beaker, 1g of cationic polyacrylamide flocculant with viscosity average molecular weight of 1200 ten thousand is slowly added under the stirring condition of 500rpm, stirring is continued for 30min, and standing is carried out for 2h, so as to obtain cationic polyacrylamide flocculant aqueous solution;
200mL of shale gas fracturing flow-back fluid is placed in a beaker, 0.5mL of the shale gas fracturing flow-back fluid composite treatment fluid provided in the embodiment 3 is added under the stirring condition of 200rpm, stirring is carried out for 20s, then 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) is added, the stirring speed is adjusted to be 60rpm, stirring is continued for 20s, and standing and sedimentation are carried out for 5min.
The processing effect data obtained in this application example are shown in table 3 below.
TABLE 3 Table 3
Wherein the suspended matter removal rate in table 3 is calculated according to the following formula:
the content of suspended matters in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In the application example, three suspended matter content determinations are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three determinations is taken as the suspended matter content in the shale gas fracturing flowback fluid before and after treatment, and specific data are 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 in SY/T5673-2020 general technical Condition for Scale inhibitor for oilfield.
In the application example, caCO (CaCO) is respectively carried out three times on the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is measured, and the average value of the results obtained by three measurements is taken as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate and specific data are shown in the following Table 3-2.
TABLE 3-2
| Temperature (temperature) | First experiment | Second experiment | Third experiment | Average value of |
| 70℃ | 95％ | 93％ | 92％ | 93％ |
The sterilization rate in table 3 was calculated according to the following formula:
the total bacterial content in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In this application example, the total bacterial content data in the pre-and post-treated shale gas fracturing flowback fluid are shown in tables 3-3 below.
TABLE 3-3
The corrosion rates in Table 3 were determined according to the method prescribed by SY/T5273-2014 corrosion inhibitor Performance evaluation method for oilfield produced water.
In the application example, three corrosion rate measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the corrosion rate of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 3-4.
Tables 3 to 4
The defoaming rate in table 3 was calculated according to the following formula:
the test of the foam volume in the formula was performed as follows: 100mL of shale gas fracturing flow-back fluid to be tested is taken and placed in a high-speed stirrer container, stirred at a high speed at 12000rpm for 1min, then immediately poured into a measuring cylinder to observe foam, and the foam volume is recorded.
In the application example, three foam volume measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the foam volume of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 3-5.
Tables 3 to 5
Application example 4
The application example provides a treatment method of shale gas fracturing flowback fluid, wherein the treatment method utilizes the shale gas fracturing flowback fluid composite treatment fluid provided in the embodiment 1, and the treatment method comprises the following steps:
200g of water is added into a 250mL beaker, 1g of cationic polyacrylamide flocculant with viscosity average molecular weight of 1000 ten thousand is slowly added under the stirring condition of 500rpm, stirring is continued for 20min, and standing is carried out for 2h, so as to obtain cationic polyacrylamide flocculant aqueous solution;
170g of water is added into a 250mL beaker, 30g of modified diatomite (conventional materials are commercially available or prepared by a conventional method in a laboratory) is slowly added under the stirring condition of 500rpm, and stirring is continued for 20min to obtain a modified diatomite suspension;
200mL of shale gas fracturing flowback fluid is placed in a beaker, 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 flowback fluid) is added into the beaker under the stirring condition of 200rpm, after the mixture is uniformly mixed, 0.6mL of the shale gas fracturing flowback fluid composite treatment liquid provided in the embodiment 1 is added, stirring is carried out for 20s, and then 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 flowback fluid) is added, the stirring speed is adjusted to be 60rpm, stirring is continued for 20s, and standing and sedimentation are carried out for 3min.
The processing effect data obtained in this application example are shown in table 4 below.
TABLE 4 Table 4
Wherein the suspended matter removal rate in table 4 was calculated according to the following formula:
the content of suspended matters in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In the application example, three suspended matter content determinations are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three determinations is taken as the suspended matter content in the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following table 4-1.
TABLE 4-1
CaCO in Table 4 3 The scale inhibition rate is measured according to the method specified in SY/T5673-2020 general technical Condition for Scale inhibitor for oilfield.
In the application example, caCO (CaCO) is respectively carried out three times on the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is measured, and the average value of the results obtained by three measurements is taken as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate and specific data are shown in the following table 4-2.
TABLE 4-2
| Temperature (temperature) | First experiment | Second experiment | Third experiment | Average value of |
| 70℃ | 95％ | 95％ | 94％ | 95％ |
The sterilization rate in table 4 was calculated according to the following formula:
the total bacterial content in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In this application example, the total bacterial content data in the pre-and post-treated shale gas fracturing flowback fluid are shown in tables 4-3 below.
TABLE 4-3
The corrosion rates in Table 4 were measured according to the method prescribed in SY/T5273-2014 corrosion inhibitor Performance evaluation method for oilfield produced water.
In the application example, three corrosion rate measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the corrosion rate of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 4-4.
Tables 4 to 4
The defoaming rate in table 4 was calculated according to the following formula:
the test of the foam volume in the formula was performed as follows: 100mL of shale gas fracturing flow-back fluid to be tested is taken and placed in a high-speed stirrer container, stirred at a high speed at 12000rpm for 1min, then immediately poured into a measuring cylinder to observe foam, and the foam volume is recorded.
In the application example, three foam volume measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the foam volume of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 4-5.
Tables 4 to 5
Application example 5
The application example provides a treatment method of shale gas fracturing flowback fluid, wherein the treatment method utilizes the shale gas fracturing flowback fluid composite treatment fluid provided in the embodiment 2, and the treatment method comprises the following steps:
200g of water is added into a 250mL beaker, 1g of cationic polyacrylamide flocculant with the viscosity average molecular weight of 800 ten thousand is slowly added under the stirring condition of 500rpm, stirring is continued for 20min, and standing is carried out for 2h, so that a cationic polyacrylamide flocculant aqueous solution is obtained;
160g of water is added into a 250mL beaker, 40g of modified diatomite (conventional materials are commercially available or can be prepared by a conventional method in a laboratory) is slowly added under the stirring condition of 500rpm, and stirring is continued for 20min to obtain a modified diatomite suspension;
placing 500mL of shale gas fracturing flowback fluid in a beaker, adding 1g of modified diatomite suspension (in the application example, the dosage of the modified diatomite is 400mg/L based on the total volume of the shale gas fracturing flowback fluid) into the beaker under the stirring condition of 200rpm, uniformly mixing, adding 1.8mL of the shale gas fracturing flowback fluid composite treatment liquid provided in the embodiment 2, stirring for 20s, adding 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 flowback fluid), adjusting the stirring speed to be 60rpm, continuing stirring for 20s, and standing and settling for 3min.
The processing effect data obtained in this application example are shown in table 5 below.
TABLE 5
Wherein the suspended matter removal rate in table 5 was calculated according to the following formula:
the content of suspended matters in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In the application example, three suspended matter content determinations are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three determinations is taken as the suspended matter content in the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following table 5-1.
TABLE 5-1
CaCO in Table 5 3 The scale inhibition rate is measured according to the method specified in SY/T5673-2020 general technical Condition for Scale inhibitor for oilfield.
In the application example, caCO (CaCO) is respectively carried out three times on the treated shale gas fracturing flowback fluid 3 The scale inhibition rate is measured, and the average value of the results obtained by three measurements is taken as CaCO of the treated shale gas fracturing flowback fluid 3 The scale inhibition rate and specific data are shown in the following Table 5-2.
TABLE 5-2
| Temperature (temperature) | First experiment | Second experiment | Third experiment | Average value of |
| 70℃ | 94％ | 94％ | 95％ | 94％ |
The sterilization rate in table 5 was calculated according to the following formula:
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the total bacterial content in the formula is according to NB/T14002.3-2015 section 3 of shale gas reservoir modification: the recovery and treatment method of the fracturing flowback fluid are determined by a method prescribed in the method.
In this application example, the total bacterial content data in the pre-and post-treated shale gas fracturing flowback fluid are shown in tables 5-3 below.
TABLE 5-3
The corrosion rates in Table 5 were measured according to the method prescribed in SY/T5273-2014 corrosion inhibitor Performance evaluation method for oilfield produced water.
In the application example, three corrosion rate measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the corrosion rate of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 5-4.
Tables 5 to 4
The defoaming rate in table 5 was calculated according to the following formula:
the test of the foam volume in the formula was performed as follows: 100mL of shale gas fracturing flow-back fluid to be tested is taken and placed in a high-speed stirrer container, stirred at a high speed at 12000rpm for 1min, then immediately poured into a measuring cylinder to observe foam, and the foam volume is recorded.
In the application example, three foam volume measurements are respectively carried out on the shale gas fracturing flowback fluid before and after treatment, and the average value of the results obtained by the three measurements is taken as the foam volume of the shale gas fracturing flowback fluid before and after treatment, and specific data are shown in the following tables 5-5.
Tables 5 to 5
In summary, as can be seen by combining the effect data in the above tables 1 to 5, the shale gas fracturing flowback fluid composite treatment fluid provided by the embodiment of the invention has multiple functions of scale inhibition, corrosion inhibition, flocculation, sterilization, defoaming and the like, and has good application prospects in shale gas fracturing flowback fluid treatment.
The foregoing description of the embodiments of the invention is not intended to limit the scope of the invention, so that the substitution of equivalent elements or equivalent variations and modifications within the scope of the invention shall fall within the scope of the patent. In addition, the technical features and the technical features, the technical features and the technical invention can be freely combined for use.
Claims (13)
1. The treatment method of the shale gas fracturing flowback fluid utilizes shale gas fracturing flowback fluid composite treatment fluid, which comprises the following steps:
adding modified diatomite into the shale gas fracturing flowback fluid, uniformly mixing, adding the shale gas fracturing flowback fluid composite treatment fluid, uniformly mixing, adding a flocculant solution, uniformly mixing, and settling;
the dosage of the modified diatomite is 100-500mg/L, the dosage of the shale gas fracturing flow-back fluid composite treatment fluid is 0.1-0.8%, and the dosage of the flocculant is 5-20mg/L based on the total volume of the shale gas fracturing flow-back fluid;
based on the total weight of the shale gas fracturing flow-back fluid composite treatment fluid as 100%, the shale gas fracturing flow-back fluid composite treatment fluid comprises 3-6% of neutral phosphonate components, 5-12% of inorganic flocculation components, 1.5-3% of sterilization components, 2-5% of water-soluble defoaming components and the balance of water, wherein the content of the sterilization components and the content of the water-soluble defoaming components are calculated according to the content of effective components in the sterilization components and the water-soluble defoaming components respectively;
the inorganic flocculation component is free of iron ions and sulfate ions;
the water-soluble defoaming component comprises one or a combination of a plurality of polyether defoamers and silicone defoamers.
2. The method of claim 1, wherein the flocculant is a cationic polyacrylamide.
3. The method of claim 2, wherein the cationic polyacrylamide has a viscosity average molecular weight of 150-2000 tens of thousands.
4. The method of claim 1, wherein the neutral phosphonate component comprises one or a combination of tetra sodium aminotrimethylene phosphonate, potassium hydroxyethylidene diphosphonate, pentasodium ethylenediamine tetramethylene phosphonate, pentasodium diethylenetriamine pentamethylene phosphonate, heptasodium diethylenetriamine pentamethylene phosphonate, potassium hexamethylenediamine tetramethylene phosphonate.
5. The method of claim 1 or 4, wherein the inorganic flocculating component comprises one or a combination of several of polyaluminum chloride, polyaluminum sulfatochloride, magnesium aluminum polysilicate.
6. The method of claim 1 or 4, wherein the bactericidal component comprises one or a combination of several of aldehyde bactericides, quaternary ammonium salt bactericides, isothiazolinone bactericides.
7. The method of claim 6, wherein the aldehyde sterilant comprises one or a combination of glutaraldehyde, formaldehyde, acrolein.
8. The method of claim 7, wherein the aldehyde sterilant is glutaraldehyde.
9. The method of claim 6, wherein the quaternary ammonium salt bactericide comprises one or a combination of several of tetradecyldimethylbenzyl ammonium chloride, dodecyl trimethyl ammonium chloride, dodecyl dimethylbenzyl ammonium bromide and tetramethyl ammonium chloride.
10. The method of claim 9, wherein the quaternary ammonium salt bactericide is dodecyl dimethyl benzyl ammonium chloride or tetramethyl ammonium chloride.
11. The method of claim 6, wherein the isothiazolinone bactericides comprise methyl isothiazolinone and/or methyl chloroisothiazolinone.
12. The method of claim 11, wherein the isothiazolinone fungicide is methyl isothiazolinone.
13. The method of claim 1, wherein the shale gas fracturing flow-back fluid composite treatment fluid preparation method comprises:
adding a water-soluble defoaming component into water under the stirring condition, stirring uniformly, adding a solid component in a raw material used for preparing the shale gas fracturing flow-back fluid compound treatment fluid, stirring uniformly to form a suspension, adding a liquid component in the raw material into the suspension, and stirring uniformly to obtain the suspension, namely the shale gas fracturing flow-back fluid compound treatment fluid.
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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 |
| 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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| 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 |
| 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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