US20120186811A1 - Methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove calcium carbonate and similar materials from the matrix of a formation or a proppant pack - Google Patents
Methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove calcium carbonate and similar materials from the matrix of a formation or a proppant pack Download PDFInfo
- Publication number
- US20120186811A1 US20120186811A1 US13/433,511 US201213433511A US2012186811A1 US 20120186811 A1 US20120186811 A1 US 20120186811A1 US 201213433511 A US201213433511 A US 201213433511A US 2012186811 A1 US2012186811 A1 US 2012186811A1
- Authority
- US
- United States
- Prior art keywords
- treatment fluid
- viscosity
- chelating agent
- wellbore
- introducing
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 239000012530 fluid Substances 0.000 title claims abstract description 121
- 230000015572 biosynthetic process Effects 0.000 title claims abstract description 61
- 238000000034 method Methods 0.000 title claims abstract description 60
- 239000002738 chelating agent Substances 0.000 title claims abstract description 32
- 239000011159 matrix material Substances 0.000 title claims abstract description 21
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 title claims description 14
- 229910000019 calcium carbonate Inorganic materials 0.000 title claims description 7
- 239000000463 material Substances 0.000 title description 11
- 238000004519 manufacturing process Methods 0.000 title description 7
- 230000004936 stimulating effect Effects 0.000 title 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 42
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 37
- 150000002500 ions Chemical class 0.000 claims abstract description 7
- 125000000623 heterocyclic group Chemical group 0.000 claims abstract description 6
- 229910021645 metal ion Inorganic materials 0.000 claims abstract description 6
- 229910052755 nonmetal Inorganic materials 0.000 claims abstract description 5
- 239000004094 surface-active agent Substances 0.000 claims description 34
- -1 methyl ester sulfonates Chemical class 0.000 claims description 15
- BHPQYMZQTOCNFJ-UHFFFAOYSA-N Calcium cation Chemical compound [Ca+2] BHPQYMZQTOCNFJ-UHFFFAOYSA-N 0.000 claims description 9
- 229910001424 calcium ion Inorganic materials 0.000 claims description 9
- 229920006395 saturated elastomer Polymers 0.000 claims description 9
- 150000001412 amines Chemical class 0.000 claims description 8
- KWIUHFFTVRNATP-UHFFFAOYSA-N Betaine Natural products C[N+](C)(C)CC([O-])=O KWIUHFFTVRNATP-UHFFFAOYSA-N 0.000 claims description 6
- 239000002253 acid Substances 0.000 claims description 6
- 229960003237 betaine Drugs 0.000 claims description 6
- 239000012153 distilled water Substances 0.000 claims description 6
- 239000012085 test solution Substances 0.000 claims description 5
- URDCARMUOSMFFI-UHFFFAOYSA-N 2-[2-[bis(carboxymethyl)amino]ethyl-(2-hydroxyethyl)amino]acetic acid Chemical compound OCCN(CC(O)=O)CCN(CC(O)=O)CC(O)=O URDCARMUOSMFFI-UHFFFAOYSA-N 0.000 claims description 4
- XNCSCQSQSGDGES-UHFFFAOYSA-N 2-[2-[bis(carboxymethyl)amino]propyl-(carboxymethyl)amino]acetic acid Chemical compound OC(=O)CN(CC(O)=O)C(C)CN(CC(O)=O)CC(O)=O XNCSCQSQSGDGES-UHFFFAOYSA-N 0.000 claims description 4
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 claims description 4
- KCXVZYZYPLLWCC-UHFFFAOYSA-N EDTA Chemical compound OC(=O)CN(CC(O)=O)CCN(CC(O)=O)CC(O)=O KCXVZYZYPLLWCC-UHFFFAOYSA-N 0.000 claims description 4
- QPCDCPDFJACHGM-UHFFFAOYSA-N N,N-bis{2-[bis(carboxymethyl)amino]ethyl}glycine Chemical compound OC(=O)CN(CC(O)=O)CCN(CC(=O)O)CCN(CC(O)=O)CC(O)=O QPCDCPDFJACHGM-UHFFFAOYSA-N 0.000 claims description 4
- 150000001298 alcohols Chemical class 0.000 claims description 4
- 150000003863 ammonium salts Chemical class 0.000 claims description 4
- DGAQECJNVWCQMB-PUAWFVPOSA-M Ilexoside XXIX Chemical compound C[C@@H]1CC[C@@]2(CC[C@@]3(C(=CC[C@H]4[C@]3(CC[C@@H]5[C@@]4(CC[C@@H](C5(C)C)OS(=O)(=O)[O-])C)C)[C@@H]2[C@]1(C)O)C)C(=O)O[C@H]6[C@@H]([C@H]([C@@H]([C@H](O6)CO)O)O)O.[Na+] DGAQECJNVWCQMB-PUAWFVPOSA-M 0.000 claims description 3
- JNGWKQJZIUZUPR-UHFFFAOYSA-N [3-(dodecanoylamino)propyl](hydroxy)dimethylammonium Chemical compound CCCCCCCCCCCC(=O)NCCC[N+](C)(C)[O-] JNGWKQJZIUZUPR-UHFFFAOYSA-N 0.000 claims description 3
- MRUAUOIMASANKQ-UHFFFAOYSA-O carboxymethyl-[3-(dodecanoylamino)propyl]-dimethylazanium Chemical compound CCCCCCCCCCCC(=O)NCCC[N+](C)(C)CC(O)=O MRUAUOIMASANKQ-UHFFFAOYSA-O 0.000 claims description 3
- 238000005187 foaming Methods 0.000 claims description 3
- 239000011734 sodium Substances 0.000 claims description 3
- 229910052708 sodium Inorganic materials 0.000 claims description 3
- ULUAUXLGCMPNKK-UHFFFAOYSA-N Sulfobutanedioic acid Chemical class OC(=O)CC(C(O)=O)S(O)(=O)=O ULUAUXLGCMPNKK-UHFFFAOYSA-N 0.000 claims description 2
- XYZGDYPGGXDMGG-QVTWQEFQSA-J [Na+].[Na+].[Na+].[Na+].[O-]C(=O)CC[C@H](NC(C([O-])=O)C([O-])=O)C([O-])=O Chemical compound [Na+].[Na+].[Na+].[Na+].[O-]C(=O)CC[C@H](NC(C([O-])=O)C([O-])=O)C([O-])=O XYZGDYPGGXDMGG-QVTWQEFQSA-J 0.000 claims description 2
- 239000000654 additive Substances 0.000 claims description 2
- 230000000996 additive effect Effects 0.000 claims description 2
- 150000003973 alkyl amines Chemical class 0.000 claims description 2
- 150000001408 amides Chemical class 0.000 claims description 2
- 235000014113 dietary fatty acids Nutrition 0.000 claims description 2
- LQZZUXJYWNFBMV-UHFFFAOYSA-N dodecan-1-ol Chemical compound CCCCCCCCCCCCO LQZZUXJYWNFBMV-UHFFFAOYSA-N 0.000 claims description 2
- PZZHMLOHNYWKIK-UHFFFAOYSA-N eddha Chemical compound C=1C=CC=C(O)C=1C(C(=O)O)NCCNC(C(O)=O)C1=CC=CC=C1O PZZHMLOHNYWKIK-UHFFFAOYSA-N 0.000 claims description 2
- 239000000194 fatty acid Substances 0.000 claims description 2
- 229930195729 fatty acid Natural products 0.000 claims description 2
- 150000004665 fatty acids Chemical class 0.000 claims description 2
- 238000002347 injection Methods 0.000 claims description 2
- 239000007924 injection Substances 0.000 claims description 2
- MGFYIUFZLHCRTH-UHFFFAOYSA-N nitrilotriacetic acid Chemical compound OC(=O)CN(CC(O)=O)CC(O)=O MGFYIUFZLHCRTH-UHFFFAOYSA-N 0.000 claims description 2
- 229920000847 nonoxynol Polymers 0.000 claims description 2
- SNQQPOLDUKLAAF-UHFFFAOYSA-N nonylphenol Chemical class CCCCCCCCCC1=CC=CC=C1O SNQQPOLDUKLAAF-UHFFFAOYSA-N 0.000 claims description 2
- 229960003330 pentetic acid Drugs 0.000 claims description 2
- XAEFZNCEHLXOMS-UHFFFAOYSA-M potassium benzoate Chemical compound [K+].[O-]C(=O)C1=CC=CC=C1 XAEFZNCEHLXOMS-UHFFFAOYSA-M 0.000 claims description 2
- 150000003856 quaternary ammonium compounds Chemical class 0.000 claims description 2
- 239000003760 tallow Substances 0.000 claims description 2
- UZVUJVFQFNHRSY-OUTKXMMCSA-J tetrasodium;(2s)-2-[bis(carboxylatomethyl)amino]pentanedioate Chemical compound [Na+].[Na+].[Na+].[Na+].[O-]C(=O)CC[C@@H](C([O-])=O)N(CC([O-])=O)CC([O-])=O UZVUJVFQFNHRSY-OUTKXMMCSA-J 0.000 claims description 2
- 238000005755 formation reaction Methods 0.000 description 45
- 239000000203 mixture Substances 0.000 description 15
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 12
- 230000035699 permeability Effects 0.000 description 11
- 150000001875 compounds Chemical class 0.000 description 8
- 230000035515 penetration Effects 0.000 description 7
- 102000004190 Enzymes Human genes 0.000 description 6
- 108090000790 Enzymes Proteins 0.000 description 6
- 239000003431 cross linking reagent Substances 0.000 description 6
- 239000007789 gas Substances 0.000 description 6
- 239000000126 substance Substances 0.000 description 6
- 230000002378 acidificating effect Effects 0.000 description 5
- 230000008901 benefit Effects 0.000 description 5
- 229910017053 inorganic salt Inorganic materials 0.000 description 5
- 239000004215 Carbon black (E152) Substances 0.000 description 4
- RTZKZFJDLAIYFH-UHFFFAOYSA-N Diethyl ether Chemical compound CCOCC RTZKZFJDLAIYFH-UHFFFAOYSA-N 0.000 description 4
- KWIUHFFTVRNATP-UHFFFAOYSA-O N,N,N-trimethylglycinium Chemical compound C[N+](C)(C)CC(O)=O KWIUHFFTVRNATP-UHFFFAOYSA-O 0.000 description 4
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 4
- 125000000217 alkyl group Chemical group 0.000 description 4
- 229910000514 dolomite Inorganic materials 0.000 description 4
- RAQDACVRFCEPDA-UHFFFAOYSA-L ferrous carbonate Chemical compound [Fe+2].[O-]C([O-])=O RAQDACVRFCEPDA-UHFFFAOYSA-L 0.000 description 4
- 229930195733 hydrocarbon Natural products 0.000 description 4
- 150000002430 hydrocarbons Chemical class 0.000 description 4
- 239000007787 solid Substances 0.000 description 4
- 230000000638 stimulation Effects 0.000 description 4
- 239000010459 dolomite Substances 0.000 description 3
- 150000004676 glycans Chemical class 0.000 description 3
- 229920000642 polymer Polymers 0.000 description 3
- 229920001282 polysaccharide Polymers 0.000 description 3
- 239000005017 polysaccharide Substances 0.000 description 3
- GJCOSYZMQJWQCA-UHFFFAOYSA-N 9H-xanthene Chemical compound C1=CC=C2CC3=CC=CC=C3OC2=C1 GJCOSYZMQJWQCA-UHFFFAOYSA-N 0.000 description 2
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- XTEGARKTQYYJKE-UHFFFAOYSA-M Chlorate Chemical compound [O-]Cl(=O)=O XTEGARKTQYYJKE-UHFFFAOYSA-M 0.000 description 2
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 2
- 235000019738 Limestone Nutrition 0.000 description 2
- FYYHWMGAXLPEAU-UHFFFAOYSA-N Magnesium Chemical compound [Mg] FYYHWMGAXLPEAU-UHFFFAOYSA-N 0.000 description 2
- OKIZCWYLBDKLSU-UHFFFAOYSA-M N,N,N-Trimethylmethanaminium chloride Chemical compound [Cl-].C[N+](C)(C)C OKIZCWYLBDKLSU-UHFFFAOYSA-M 0.000 description 2
- ZLMJMSJWJFRBEC-UHFFFAOYSA-N Potassium Chemical compound [K] ZLMJMSJWJFRBEC-UHFFFAOYSA-N 0.000 description 2
- 229920002472 Starch Polymers 0.000 description 2
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 description 2
- 150000001336 alkenes Chemical class 0.000 description 2
- 239000007864 aqueous solution Substances 0.000 description 2
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 2
- 229920001222 biopolymer Polymers 0.000 description 2
- 239000012267 brine Substances 0.000 description 2
- OSGAYBCDTDRGGQ-UHFFFAOYSA-L calcium sulfate Chemical compound [Ca+2].[O-]S([O-])(=O)=O OSGAYBCDTDRGGQ-UHFFFAOYSA-L 0.000 description 2
- 239000013522 chelant Substances 0.000 description 2
- 238000006243 chemical reaction Methods 0.000 description 2
- 230000007797 corrosion Effects 0.000 description 2
- 238000005260 corrosion Methods 0.000 description 2
- 230000003111 delayed effect Effects 0.000 description 2
- 239000006260 foam Substances 0.000 description 2
- WQYVRQLZKVEZGA-UHFFFAOYSA-N hypochlorite Chemical compound Cl[O-] WQYVRQLZKVEZGA-UHFFFAOYSA-N 0.000 description 2
- 229910052500 inorganic mineral Inorganic materials 0.000 description 2
- 239000006028 limestone Substances 0.000 description 2
- 229910052749 magnesium Inorganic materials 0.000 description 2
- 239000011777 magnesium Substances 0.000 description 2
- ZLNQQNXFFQJAID-UHFFFAOYSA-L magnesium carbonate Chemical compound [Mg+2].[O-]C([O-])=O ZLNQQNXFFQJAID-UHFFFAOYSA-L 0.000 description 2
- 239000001095 magnesium carbonate Substances 0.000 description 2
- 229910000021 magnesium carbonate Inorganic materials 0.000 description 2
- 239000011707 mineral Substances 0.000 description 2
- 239000011148 porous material Substances 0.000 description 2
- 239000011591 potassium Substances 0.000 description 2
- 229910052700 potassium Inorganic materials 0.000 description 2
- 238000005067 remediation Methods 0.000 description 2
- 150000003839 salts Chemical class 0.000 description 2
- 239000011780 sodium chloride Substances 0.000 description 2
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 2
- 239000008107 starch Substances 0.000 description 2
- 235000019698 starch Nutrition 0.000 description 2
- UBXAKNTVXQMEAG-UHFFFAOYSA-L strontium sulfate Chemical compound [Sr+2].[O-]S([O-])(=O)=O UBXAKNTVXQMEAG-UHFFFAOYSA-L 0.000 description 2
- BDHFUVZGWQCTTF-UHFFFAOYSA-M sulfonate Chemical compound [O-]S(=O)=O BDHFUVZGWQCTTF-UHFFFAOYSA-M 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- 229920001285 xanthan gum Polymers 0.000 description 2
- OVSKIKFHRZPJSS-UHFFFAOYSA-N 2,4-D Chemical compound OC(=O)COC1=CC=C(Cl)C=C1Cl OVSKIKFHRZPJSS-UHFFFAOYSA-N 0.000 description 1
- FEBUJFMRSBAMES-UHFFFAOYSA-N 2-[(2-{[3,5-dihydroxy-2-(hydroxymethyl)-6-phosphanyloxan-4-yl]oxy}-3,5-dihydroxy-6-({[3,4,5-trihydroxy-6-(hydroxymethyl)oxan-2-yl]oxy}methyl)oxan-4-yl)oxy]-3,5-dihydroxy-6-(hydroxymethyl)oxan-4-yl phosphinite Chemical compound OC1C(O)C(O)C(CO)OC1OCC1C(O)C(OC2C(C(OP)C(O)C(CO)O2)O)C(O)C(OC2C(C(CO)OC(P)C2O)O)O1 FEBUJFMRSBAMES-UHFFFAOYSA-N 0.000 description 1
- ZKWJQNCOTNUNMF-QXMHVHEDSA-N 2-[dimethyl-[3-[[(z)-octadec-9-enoyl]amino]propyl]azaniumyl]acetate Chemical compound CCCCCCCC\C=C/CCCCCCCC(=O)NCCC[N+](C)(C)CC([O-])=O ZKWJQNCOTNUNMF-QXMHVHEDSA-N 0.000 description 1
- PUAQLLVFLMYYJJ-UHFFFAOYSA-N 2-aminopropiophenone Chemical compound CC(N)C(=O)C1=CC=CC=C1 PUAQLLVFLMYYJJ-UHFFFAOYSA-N 0.000 description 1
- BTBUEUYNUDRHOZ-UHFFFAOYSA-N Borate Chemical compound [O-]B([O-])[O-] BTBUEUYNUDRHOZ-UHFFFAOYSA-N 0.000 description 1
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 1
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 1
- 241000040710 Chela Species 0.000 description 1
- 241000238424 Crustacea Species 0.000 description 1
- MBMLMWLHJBBADN-UHFFFAOYSA-N Ferrous sulfide Chemical compound [Fe]=S MBMLMWLHJBBADN-UHFFFAOYSA-N 0.000 description 1
- 229920002907 Guar gum Polymers 0.000 description 1
- 102000011782 Keratins Human genes 0.000 description 1
- 108010076876 Keratins Proteins 0.000 description 1
- WHXSMMKQMYFTQS-UHFFFAOYSA-N Lithium Chemical compound [Li] WHXSMMKQMYFTQS-UHFFFAOYSA-N 0.000 description 1
- 229910019142 PO4 Inorganic materials 0.000 description 1
- 229920002305 Schizophyllan Polymers 0.000 description 1
- 229920002310 Welan gum Polymers 0.000 description 1
- 229910052782 aluminium Inorganic materials 0.000 description 1
- 239000002280 amphoteric surfactant Substances 0.000 description 1
- 125000000129 anionic group Chemical group 0.000 description 1
- 229910001439 antimony ion Inorganic materials 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- SXDBWCPKPHAZSM-UHFFFAOYSA-M bromate Inorganic materials [O-]Br(=O)=O SXDBWCPKPHAZSM-UHFFFAOYSA-M 0.000 description 1
- SXDBWCPKPHAZSM-UHFFFAOYSA-N bromic acid Chemical compound OBr(=O)=O SXDBWCPKPHAZSM-UHFFFAOYSA-N 0.000 description 1
- 239000011575 calcium Substances 0.000 description 1
- 229910052791 calcium Inorganic materials 0.000 description 1
- 150000004649 carbonic acid derivatives Chemical class 0.000 description 1
- 230000015556 catabolic process Effects 0.000 description 1
- 125000002091 cationic group Chemical group 0.000 description 1
- 239000001913 cellulose Substances 0.000 description 1
- 229920002678 cellulose Polymers 0.000 description 1
- 230000008859 change Effects 0.000 description 1
- 229910001919 chlorite Inorganic materials 0.000 description 1
- 229910052619 chlorite group Inorganic materials 0.000 description 1
- QBWCMBCROVPCKQ-UHFFFAOYSA-N chlorous acid Chemical compound OCl=O QBWCMBCROVPCKQ-UHFFFAOYSA-N 0.000 description 1
- 210000000078 claw Anatomy 0.000 description 1
- 239000000470 constituent Substances 0.000 description 1
- 238000006731 degradation reaction Methods 0.000 description 1
- 238000011161 development Methods 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000000945 filler Substances 0.000 description 1
- 239000000665 guar gum Substances 0.000 description 1
- 229960002154 guar gum Drugs 0.000 description 1
- 235000010417 guar gum Nutrition 0.000 description 1
- 230000007062 hydrolysis Effects 0.000 description 1
- 238000006460 hydrolysis reaction Methods 0.000 description 1
- XLYOFNOQVPJJNP-UHFFFAOYSA-M hydroxide Chemical compound [OH-] XLYOFNOQVPJJNP-UHFFFAOYSA-M 0.000 description 1
- 238000011065 in-situ storage Methods 0.000 description 1
- 229910052742 iron Inorganic materials 0.000 description 1
- UQSXHKLRYXJYBZ-UHFFFAOYSA-N iron oxide Inorganic materials [Fe]=O UQSXHKLRYXJYBZ-UHFFFAOYSA-N 0.000 description 1
- 235000013980 iron oxide Nutrition 0.000 description 1
- VBMVTYDPPZVILR-UHFFFAOYSA-N iron(2+);oxygen(2-) Chemical class [O-2].[Fe+2] VBMVTYDPPZVILR-UHFFFAOYSA-N 0.000 description 1
- 239000007788 liquid Substances 0.000 description 1
- 229910052744 lithium Inorganic materials 0.000 description 1
- 241000238565 lobster Species 0.000 description 1
- 239000000693 micelle Substances 0.000 description 1
- 150000007522 mineralic acids Chemical class 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 230000009972 noncorrosive effect Effects 0.000 description 1
- 150000002894 organic compounds Chemical class 0.000 description 1
- 150000001451 organic peroxides Chemical class 0.000 description 1
- 239000007800 oxidant agent Substances 0.000 description 1
- 230000001590 oxidative effect Effects 0.000 description 1
- KHIWWQKSHDUIBK-UHFFFAOYSA-N periodic acid Chemical compound OI(=O)(=O)=O KHIWWQKSHDUIBK-UHFFFAOYSA-N 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
- 235000021317 phosphate Nutrition 0.000 description 1
- 150000003013 phosphoric acid derivatives Chemical class 0.000 description 1
- 239000002244 precipitate Substances 0.000 description 1
- 230000008569 process Effects 0.000 description 1
- 230000000246 remedial effect Effects 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 239000013535 sea water Substances 0.000 description 1
- 150000004760 silicates Chemical class 0.000 description 1
- 239000000243 solution Substances 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
- 239000010936 titanium Substances 0.000 description 1
- 229910052719 titanium Inorganic materials 0.000 description 1
- 229910052726 zirconium Inorganic materials 0.000 description 1
Classifications
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/536—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning characterised by their form or by the form of their components, e.g. encapsulated material
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
Definitions
- the invention generally relates to production enhancement to increase hydrocarbon production from a subterranean formation. More particularly, the invention relates to methods of treating a portion of a matrix of a subterranean formation or a proppant pack in a pre-existing fracture or perforation to increase permeability and enhance production, some of which techniques are referred to as near-wellbore stimulation.
- a method for treating a portion of a subterranean formation or a proppant pack comprises the steps of: (A) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.
- the purpose of this invention is to improve delivery of a chelating agent for production enhancement by increasing the viscosity of the treatment fluid.
- a chelating agent can be utilized to help dissolve and remove carbonates and other minerals from the matrix of the subterranean formation or the proppant pack.
- the concentration of the chelating agent is sufficient to help dissolve a substantial amount of carbonate material.
- the treatment fluid containing the chelating agent includes a viscosity-increasing agent to help with placement of the fluid into the formation or proppant pack or to help with diversion of the treatment fluid. When the viscosity of the fluid is increased or gelled, the treatment fluid can provide better coverage and diversion, and thereafter be broken for flowback from the well.
- the treatment fluid can be a single fluid that dissolves calcium/magnesium/iron carbonate solids in the matrix of the near region surrounding a wellbore, a pre-existing gravel pack, a pre-existing perforation, or a pre-existing fracture or that dissolves these solids in a proppant pack in a pre-existing perforation or a pre-existing fracture.
- the treatment fluid dissolves such solids at a controlled rate and under a wide range of conditions, especially over a broad range of pH and time.
- the invention can be advantageous because it can provide methods for treating the matrix of a subterranean formation or a pre-existing proppant pack for such purposes using treatment fluids that are non-acid containing and non-corrosive.
- the treatment methods according to the invention are expected to be effective for applications associated with well completion and remediation, including: removal of carbonate scale from the formation and fractures in the formation; removal of carbonate from formations or proppant packs where the carbonate lines pore throats; stimulation for carbonate containing formations where the use of acidic fluids might be problematic, for example, in high-temperature formations due to reaction rates, or due to corrosion, etc.
- a stimulation treatment the purpose is to improve the skin of the matrix of the formation over its original condition, and a greater depth of matrix penetration is desirable.
- the treatment method is used as a remedial cleanup after a prior stimulation treatment.
- the new approach is a method for treating a portion of a subterranean formation or proppant pack, the method comprising the steps of: (A) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.
- into the matrix of the formation or the proppant pack means into the rock around the wellbore, a pre-existing perforation, or a pre-existing fracture, or into the matrix of a proppant pack in a gravel pack in the wellbore, a pre-existing perforation, or a pre-existing fracture.
- the method is adapted to be used after drilling a wellbore, either during completion or remediation of a well.
- the chelating agent in the treatment fluid can react with and dissolve calcium carbonate, magnesium carbonate, dolomite, iron carbonate, and similar materials of the formation to increase the permeability of the formation. It can also be used to help remove carbonate from formations where the carbonate lines the pore throats in the matrix of the formation, whereby the permeability of the formation can be increased and hydrocarbon production enhanced. It is desirable to allow the treatment fluid to contact the matrix of the formation or the proppant pack for a sufficient time to dissolve such carbonate materials.
- CaCO 3 is known as limestone; and CaMg(CO 3 ) 2 is known as dolomite or dolomitic limestone, both of which are minerals that are often present in subterranean formations or which may precipitate from water as scale in subterranean formations or proppant packs.
- Typical scales are of calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, various silicates and phosphates and oxides, or any of a number of compounds insoluble or slightly soluble in water.
- the chelating agent can be helpful in removing calcium carbonate, magnesium carbonate, dolomite, iron carbonate, and similar materials of scale.
- to chelate means to combine a metal ion with a chemical compound to form a ring.
- the water further includes a water-soluble inorganic salt dissolved therein.
- the purpose of the inorganic salt can be, for example, to weight the water of the treatment fluid or to make the treatment fluid more compatible and less damaging to the subterranean formation.
- a source of at least a portion of the water and the inorganic salt can be selected from the group consisting of natural or synthetic brine or seawater.
- Inorganic salt or salts can also be mixed with the water of the treatment fluid to artificially make up or increase the inorganic salt content in the water.
- a water-soluble salt replacement can be utilized such as tetramethyl ammonium chloride (TMAC) and similar organic compounds.
- TMAC tetramethyl ammonium chloride
- the pH of the treatment fluid is equal to or greater than 2, which is above the pH of strong inorganic acids that have been used to help dissolve and remove carbonate materials from the formation.
- the pH of the treatment fluid is equal to or greater than 5, which is well above the pH of spent acid fluids used for the purpose of removing carbonate, where the pH of an acid fluid is typically less than about 3.5.
- the compositions of the present invention can be used to help dissolve and remove carbonate materials from the formation with less acidic compositions. In some applications, acidic compositions can be damaging to the well or hydrocarbon production.
- the pH of the treatment fluid is in the range of 6-12, which can be used to avoid or reduce the use of substantially acidic compositions in treating the formation. It is important to note, of course, that different chelating agents work better in certain pH ranges than other ranges. Some chelating agents can be effective in the higher pH ranges. One skilled in the art would also recognize the obvious advantage of using a non-acid fluid may reduce the rate of corrosion.
- the chelating agent is selected to be effective for chelating at least calcium ions. It is also highly desirable that the chelating agent is soluble in distilled water at standard temperature and pressure at a concentration of at least 0.2 mole-equivalent for calcium ions per liter of the distilled water. As a test for whether or not the chelating agent would be effective for use in the present invention, it is believed that a solution of the chelating agent at a concentration of 0.2 mole-equivalent for calcium ions per liter of the distilled water should be effective for chelating at least 0.1 mole calcium ions per liter.
- the test solution is effective when adjusted to have a pH in the range of 5-6. More preferably, the test solution is effective when adjusted to have a pH in the range of 6-8.
- the test solution is effective when adjusted to have a pH in the range of 6-8.
- Similar tests can be performed for other ions such as magnesium, iron, etc.
- the chelating agent is preferably selected from the group consisting of ethylenediamine tetraacetic acid (“EDTA”), nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid (“HEDTA”), diethylenetriaminepentaacetic acid (“DTPA”), propylenediaminetetraacetic acid (“PDTA”), ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), a sodium or potassium salt of any of the foregoing, dicarboxymethyl glutamic acid tetrasodium salt (“GLDA”), a derivative of any of the foregoing or any combination in any proportion thereof.
- EDTA ethylenediamine tetraacetic acid
- NTA nitrilotriacetic acid
- HEDTA hydroxyethylethylenediaminetriacetic acid
- DTPA diethylenetriaminepentaacetic acid
- PDTA propylenediaminete
- the chelating agent is preferably at a concentration of at least 0.01% by weight of the water. More preferably, the chelating agent is at a concentration in the range of 1% to 80% by weight of the water.
- the viscosity-increasing agent would typically comprise a polymeric material.
- the polymeric material is preferably selected from the group consisting of: guar gum and its derivatives, cellulose derivatives, welan gum, xanthan biopolymer and its derivatives, diutan, and its derivatives, scleroglucan and its derivatives, succinoglycan biopolymer and its derivatives, and any combination of any of the foregoing in any proportion.
- Derivatives can include, for example, industrially manufactured chemical derivatives, bioengineered chemical derivatives, or naturally occurring derivatives produced by mutated organisms producing the polymer.
- a preferred polymer is of the nature taught in U.S. Patent Application Serial No. 20060014648, which is incorporated herein by reference in its entirety.
- the viscosity-increasing agent can advantageously comprise a viscoelastic surfactant.
- a viscoelastic surfactant may comprise any viscoelastic surfactant known in the art, any derivative thereof, or any combination thereof.
- the term “viscoelastic surfactant” refers to a surfactant that imparts or is capable of imparting viscoelastic behavior to a fluid due, at least in part, to the association of surfactant molecules to form viscosifying micelles.
- These viscoelastic surfactants may be cationic, anionic, nonionic, or amphoteric/zwitterionic in nature.
- the viscoelastic surfactants may comprise any number of different compounds, including methyl ester sulfonates (e.g., as described in U.S. patent application Ser. Nos. 11/058,660 (US Patent Publication No. 2006/0180310), 11/058,475 (US Patent Publication No. 2006/0180308), 11/058,612 (US Patent Publication No. 2006/0180309), and 11/058,611 (US Patent Publication No. 20060183646), filed Feb. 15, 2005, each of which is assigned to Halliburton Energy Services, Inc., the relevant disclosures of which are incorporated herein by reference), hydrolyzed keratin (e.g., as described in U.S. Pat. No.
- sulfosuccinates taurates, amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty amines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate), betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl betaine), quaternary ammonium compounds (e.g., trimethyltallowammonium chloride, trimethylcocoammonium chloride), derivatives of any of the foregoing, and any combinations of any of the foregoing in any proportion.
- alkoxylated alcohols e.g., lauryl alcohol ethoxylate, ethoxylated nonyl phenol
- ethoxylated fatty amines
- Suitable viscoelastic surfactants may comprise mixtures of several different compounds, including but not limited to: mixtures of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant; and any combination of the foregoing mixtures in any proportion
- Examples of commercially-available viscoelastic surfactants suitable for use in the present invention may include, but are not limited to, Mirataine BET-O 30TM (an oleamidopropyl betaine surfactant available from Rhodia Inc., Cranbury, N.J.), Aromox APA-TTM (an amine oxide surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethoquad O/12 PGTM (a fatty amine ethoxylate quat surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen T/12TM (a fatty amine ethoxylate surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen S/12TM (a fatty amine ethoxylate surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), and Rewoteric AM TEGTM (a tallow dihydroxyethyl betaine amphoteric surfactant available from Degussa Corp., Par
- the viscosity-increasing agent is at a concentration in the treatment fluid that is at least sufficient to make the viscosity of the treatment fluid greater than water. More preferably, the viscosity-increasing agent is at a concentration in the treatment fluid that is sufficient to make the viscosity of the treatment fluid greater than 5 cP when measured at 511 reciprocal seconds on a Fann 35A model viscometer with a number 1 spring and bob.
- the viscosity-increasing agent is at a concentration in the treatment fluid that is sufficient to make the viscosity of the treatment fluid in the range of 10 cP to 100 cP when measured at 511 reciprocal seconds on a Fann 35A model viscometer with a number 1 spring and bob.
- the viscosity-increasing polymeric agent is at a concentration of at least 0.05% by weight of the water. More preferably, the viscosity-increasing agent is at a concentration in the range of 0.05% to 10% by weight of the water.
- the treatment fluid further comprises a crosslinking agent to crosslink the polymeric material of the viscosity-increasing agent.
- a crosslinking agent to crosslink the polymeric material of the viscosity-increasing agent.
- the crosslinking agent is selected from the group consisting of: borate releasing compounds, a source of titanium ions, a source of zirconium ions, a source of antimony ions, a source of aluminum ions, a source of periodate ions, a source of permanganate ions, and any combination thereof in any proportion.
- the crosslinking agent is at a concentration of at least 0.025% by weight of the water.
- the crosslinking agent is at a concentration in the range of 0.025% to about 1% by weight of the water.
- the treatment fluid preferably further comprises a breaker adapted to break the viscosity-increasing agent.
- a breaker adapted to break the viscosity-increasing agent.
- the breaker is selected to be effective for breaking a polysaccharide-based viscosity-increasing agent.
- the breaker can be, for example, an enzyme.
- the enzyme is selected to be effective for breaking starch.
- an enzyme breaker is at a concentration of at least 0.01 lb per 1000 gal of the water.
- the enzyme breaker is at a concentration in the range of 0.01 lb to 40 lb per 1000 gal of the water.
- enzymes are often used as liquid compositions and that the above mentioned values are for fully formulated dry enzyme breakers that typically contain a large percentage of fillers.
- a breaker is employed for the viscosity-increasing agent
- the breaker is at a concentration that is at least sufficient to substantially reduce the viscosity produced by the viscosity producing agent in the treatment fluid.
- a preferred embodiment of the method according to the invention includes the steps of allowing time for the breaker to break the viscosity of the treatment fluid and then flowing back the broken fluid from the wellbore.
- the breaker is preferably an oxidizer selected from the group consisting of: a persulfate; a perborate; a bromate; a periodate; a chlorate; a chlorite; a hypochlorite, an organic peroxide; and any combination thereof in any proportion. Further, the breaker is more preferably selected from the group consisting of a lithium, sodium, potassium, or ammonium salt of any of the foregoing, and any combination thereof in any proportion.
- the oxidizing breaker for breaking a viscosity-increasing agent internal to the treatment fluid is preferably at a concentration of at least 0.01 lb per 1000 gal of the water. More preferably, such a breaker is at a concentration in the range of 0.1 to 200 per 1000 gal of the water.
- the breaker be a delayed release breaker.
- One technique for making a delayed breaker is to coat or encapsulate the breaker to delay the release of the breaker into the water.
- Another technique is to generate the breaker in situ over time or upon a change in pH of the treatment fluid.
- the method further includes the step of: after introducing the treatment fluid into the wellbore, allowing the viscosity of the treatment fluid to break to a substantially lower viscosity fluid while down hole.
- the method further comprises the step of: after allowing the viscosity of the treatment fluid to break, flowing the fluid back from the well.
- the treatment fluid can further comprise a breaker to be carried by the treatment fluid into the wellbore for breaking a viscosity-increasing agent that is external of the treatment fluid.
- the breaker for the viscosity-increasing agent in the treatment fluid is preferably at a concentration in an external aqueous fluid that is at least sufficient to substantially break the viscosity of the treatment fluid.
- the breaker for a viscosity-increasing agent that is external to the treatment fluid can be the same or different than the breaker for the viscosity-increasing agent in the treatment fluid.
- the additional or different breaker for breaking a viscosity-increasing agent external to the treatment fluid is preferably at a concentration of at least 0.01 lb per 1000 gal of the water. More preferably, the breaker is at a concentration in the range of 0.1 lb to 200 lb per 1000 gal of the water.
- the methods according to the invention can include foaming of the treatment fluid.
- the treatment fluid further comprises: an additive for foaming.
- the treatment fluid may be formed at a remote location and provided to the well site for the treatment method, or it can be formed locally at the well site.
- the treatment fluid preferably further comprises: a sufficient gas to form a foam.
- foam also refers to commingled fluids.
- the gas would be mixed with the other constituents of the treatment fluid at the well site to form a foamed or co-mingled fluid.
- the gas is selected from the group consisting of: air, CO 2 , nitrogen, and any combination thereof in any proportion. In applications of the method utilizing a gas, typically, the gas is at a concentration in the range of 5% to 95% by volume of the water.
- the step of introducing the treatment fluid into the wellbore further comprises: introducing the treatment fluid at a rate and pressure below the fracture gradient of the subterranean formation.
- the treatment fluid is applied such that the treatment fluid is introduced such that the proppant pack of a previously generated fracture or gravel pack is treated.
- the permeability of the matrix of the surrounding formation would be expected to be relatively high.
- the treatment fluid is applied such that the portion of the subterranean formation is a portion surrounding the wellbore, and wherein the treatment fluid is introduced such that the portion surrounding the wellbore is expected to be saturated to a depth of at least 1 foot. More preferably, the treatment fluid is applied such that the portion surrounding the wellbore is expected to be saturated to a depth in the range of 1 foot to 3 feet.
- desired or expected depth of penetration into the surrounding matrix of the formation will not necessarily be perfectly uniform.
- parameters for designing a treatment for a desired or expected depth of penetration are well known in the art, including, for example, the length of the wellbore to be treated and the volume of treatment fluid injected into the wellbore.
- a deeper penetration may be desired or obtained in formations with higher permeability.
- the permeability of the matrix of the surrounding formation would be expected to be relatively low.
- the portion of the subterranean formation is an area surrounding a fracture extending into the formation, and the treatment fluid is introduced such that the surrounding area is expected to be saturated to a depth of at least 0.1 inches. More preferably, the treatment fluid is introduced into the wellbore under conditions such that the area surrounding the fracture is expected to be saturated to a depth in the range of 0.1 inches to 2 inches.
- a deeper penetration may be desired or obtained in formations with higher permeability.
- the portion of the subterranean formation is a perforation tunnel
- the treatment fluid is introduced such that the perforation tunnel and the surrounding area is expected to be saturated to a depth of at least 0.1 inches. More preferably, the treatment fluid is introduced into the wellbore under conditions such that the area surrounding the perforation tunnel is expected to be saturated to a depth in the range of 0.1 inches to 2 inches.
- the treatment fluid is introduced into the wellbore under conditions such that the area surrounding the perforation tunnel is expected to be saturated to a depth in the range of 0.1 inches to 2 inches.
- the methods further comprise the step of: after the step of introducing the treatment fluid, introducing a non-viscosified treatment fluid into the wellbore, wherein the non-viscosified treatment fluid comprises: water and a chelating agent, without any substantial concentration of any viscosity-increasing agent.
- the viscosified treatment fluid is capable of moving into zones of the subterranean formation that have relatively higher permeability, thereby diverting the non-viscosified treatment fluid into zones of the subterranean formation that have relatively lower permeability.
- the injection pressure is preferably maintained from the step of introducing the treatment fluid to the step of introducing the non-viscosified treatment fluid.
- the methods further comprise the step of: applying an afterflush fluid to the portion of the subterranean formation.
- the afterflush fluid can comprise: water, a gas, a brine, a hydrocarbon, or a mixture thereof.
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Abstract
A method for treating a portion of a subterranean formation or a proppant pack is provided. In general, the method comprises the steps of: (A) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.
Description
- This is a divisional of U.S. application Ser. No. 11/801,209 filed May 10, 2007 (Attorney Docket No. 2006-IP-020127U1).
- Not applicable
- Not applicable
- The invention generally relates to production enhancement to increase hydrocarbon production from a subterranean formation. More particularly, the invention relates to methods of treating a portion of a matrix of a subterranean formation or a proppant pack in a pre-existing fracture or perforation to increase permeability and enhance production, some of which techniques are referred to as near-wellbore stimulation.
- According to the invention, a method for treating a portion of a subterranean formation or a proppant pack is provided. In general, the method comprises the steps of: (A) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.
- Other and further objects, features and advantages of the present invention will be readily apparent to those skilled in the art when the following description of the preferred embodiments is read in conjunction with the accompanying drawings
- In general, the purpose of this invention is to improve delivery of a chelating agent for production enhancement by increasing the viscosity of the treatment fluid. A chelating agent can be utilized to help dissolve and remove carbonates and other minerals from the matrix of the subterranean formation or the proppant pack. The concentration of the chelating agent is sufficient to help dissolve a substantial amount of carbonate material. The treatment fluid containing the chelating agent includes a viscosity-increasing agent to help with placement of the fluid into the formation or proppant pack or to help with diversion of the treatment fluid. When the viscosity of the fluid is increased or gelled, the treatment fluid can provide better coverage and diversion, and thereafter be broken for flowback from the well. The treatment fluid can be a single fluid that dissolves calcium/magnesium/iron carbonate solids in the matrix of the near region surrounding a wellbore, a pre-existing gravel pack, a pre-existing perforation, or a pre-existing fracture or that dissolves these solids in a proppant pack in a pre-existing perforation or a pre-existing fracture. The treatment fluid dissolves such solids at a controlled rate and under a wide range of conditions, especially over a broad range of pH and time. The invention can be advantageous because it can provide methods for treating the matrix of a subterranean formation or a pre-existing proppant pack for such purposes using treatment fluids that are non-acid containing and non-corrosive.
- The treatment methods according to the invention are expected to be effective for applications associated with well completion and remediation, including: removal of carbonate scale from the formation and fractures in the formation; removal of carbonate from formations or proppant packs where the carbonate lines pore throats; stimulation for carbonate containing formations where the use of acidic fluids might be problematic, for example, in high-temperature formations due to reaction rates, or due to corrosion, etc. For a stimulation treatment, the purpose is to improve the skin of the matrix of the formation over its original condition, and a greater depth of matrix penetration is desirable. For a damage removal treatment, such as after a prior gel treatment or completion damage, less depth of penetration can be sufficient (all else being equal), where the purpose of the damage removal is to get the permeability of the matrix of the formation back toward its original condition. According to a presently preferred embodiment, the treatment method is used as a remedial cleanup after a prior stimulation treatment.
- As used herein, the words “comprise,” “has,” and “include” and all grammatical variations thereof are each intended to have an open, non-limiting meaning that does not exclude additional elements or steps.
- In general, the new approach is a method for treating a portion of a subterranean formation or proppant pack, the method comprising the steps of: (A) forming or providing a treatment fluid comprising: (i) water; (ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and (iii) a viscosity-increasing agent; and (B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack. As used herein, “into the matrix of the formation or the proppant pack” means into the rock around the wellbore, a pre-existing perforation, or a pre-existing fracture, or into the matrix of a proppant pack in a gravel pack in the wellbore, a pre-existing perforation, or a pre-existing fracture. The method is adapted to be used after drilling a wellbore, either during completion or remediation of a well.
- It is believed that the chelating agent in the treatment fluid can react with and dissolve calcium carbonate, magnesium carbonate, dolomite, iron carbonate, and similar materials of the formation to increase the permeability of the formation. It can also be used to help remove carbonate from formations where the carbonate lines the pore throats in the matrix of the formation, whereby the permeability of the formation can be increased and hydrocarbon production enhanced. It is desirable to allow the treatment fluid to contact the matrix of the formation or the proppant pack for a sufficient time to dissolve such carbonate materials. CaCO3 is known as limestone; and CaMg(CO3)2 is known as dolomite or dolomitic limestone, both of which are minerals that are often present in subterranean formations or which may precipitate from water as scale in subterranean formations or proppant packs. Typical scales are of calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate, iron sulfide, iron oxides, iron carbonate, various silicates and phosphates and oxides, or any of a number of compounds insoluble or slightly soluble in water. Although it may not be expected to dissolve all of the components of scale, the chelating agent can be helpful in removing calcium carbonate, magnesium carbonate, dolomite, iron carbonate, and similar materials of scale.
- As used herein, to chelate means to combine a metal ion with a chemical compound to form a ring. “The adjective chelate, derived from the great claw or chela (chely—Greek) of the lobster or other crustaceans, is suggested for the caliper like groups which function as two associating units and fasten to the central atom so as to produce heterocyclic rings.” Sir Gilbert T. Morgan and H. D. K. Drew [J. Chem. Soc., 1920, 117, 1456].
- Preferably, the water further includes a water-soluble inorganic salt dissolved therein. The purpose of the inorganic salt can be, for example, to weight the water of the treatment fluid or to make the treatment fluid more compatible and less damaging to the subterranean formation. It should be understood, of course, that a source of at least a portion of the water and the inorganic salt can be selected from the group consisting of natural or synthetic brine or seawater. Inorganic salt or salts can also be mixed with the water of the treatment fluid to artificially make up or increase the inorganic salt content in the water. Alternatively for these types of purposes, a water-soluble salt replacement can be utilized such as tetramethyl ammonium chloride (TMAC) and similar organic compounds.
- It is a particular advantage of the method according to the invention to be able to help remove carbonate and similar materials without the use of strongly acidic treatment compositions, that is, without the use of treatment compositions having a pH less than 2. According to a preferred embodiment of the invention, the pH of the treatment fluid is equal to or greater than 2, which is above the pH of strong inorganic acids that have been used to help dissolve and remove carbonate materials from the formation.
- More preferably, according to the invention, the pH of the treatment fluid is equal to or greater than 5, which is well above the pH of spent acid fluids used for the purpose of removing carbonate, where the pH of an acid fluid is typically less than about 3.5. The compositions of the present invention can be used to help dissolve and remove carbonate materials from the formation with less acidic compositions. In some applications, acidic compositions can be damaging to the well or hydrocarbon production.
- Most preferably, according to the invention, the pH of the treatment fluid is in the range of 6-12, which can be used to avoid or reduce the use of substantially acidic compositions in treating the formation. It is important to note, of course, that different chelating agents work better in certain pH ranges than other ranges. Some chelating agents can be effective in the higher pH ranges. One skilled in the art would also recognize the obvious advantage of using a non-acid fluid may reduce the rate of corrosion.
- In particular, the chelating agent is selected to be effective for chelating at least calcium ions. It is also highly desirable that the chelating agent is soluble in distilled water at standard temperature and pressure at a concentration of at least 0.2 mole-equivalent for calcium ions per liter of the distilled water. As a test for whether or not the chelating agent would be effective for use in the present invention, it is believed that a solution of the chelating agent at a concentration of 0.2 mole-equivalent for calcium ions per liter of the distilled water should be effective for chelating at least 0.1 mole calcium ions per liter. Preferably, the test solution is effective when adjusted to have a pH in the range of 5-6. More preferably, the test solution is effective when adjusted to have a pH in the range of 6-8. One skilled in the art would recognize that similar tests can be performed for other ions such as magnesium, iron, etc.
- There are numerous examples of suitable chelating agents. For various reasons including effectiveness, ready availability, and economical cost, the chelating agent is preferably selected from the group consisting of ethylenediamine tetraacetic acid (“EDTA”), nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid (“HEDTA”), diethylenetriaminepentaacetic acid (“DTPA”), propylenediaminetetraacetic acid (“PDTA”), ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), a sodium or potassium salt of any of the foregoing, dicarboxymethyl glutamic acid tetrasodium salt (“GLDA”), a derivative of any of the foregoing or any combination in any proportion thereof. It is to be understood, of course, that a derivative may be employed provided that the substitution of an atom or group of atoms in the parent compound for another atom or group of atoms does not substantially impair the function of the derivative relative to the parent compound. A derivative would also include compounds that do not have the functionality, but would regain functionality due to some process in use such as a reaction, hydrolysis, degradation, etc. The chelating agent is preferably at a concentration of at least 0.01% by weight of the water. More preferably, the chelating agent is at a concentration in the range of 1% to 80% by weight of the water.
- The viscosity-increasing agent would typically comprise a polymeric material. For various reasons including effectiveness, ready availability, and economical cost, the polymeric material is preferably selected from the group consisting of: guar gum and its derivatives, cellulose derivatives, welan gum, xanthan biopolymer and its derivatives, diutan, and its derivatives, scleroglucan and its derivatives, succinoglycan biopolymer and its derivatives, and any combination of any of the foregoing in any proportion. Derivatives can include, for example, industrially manufactured chemical derivatives, bioengineered chemical derivatives, or naturally occurring derivatives produced by mutated organisms producing the polymer. A preferred polymer is of the nature taught in U.S. Patent Application Serial No. 20060014648, which is incorporated herein by reference in its entirety.
- According to another aspect of the invention, the viscosity-increasing agent can advantageously comprise a viscoelastic surfactant. One perceived advantage of a surfactant gel is that it has much less potential for leaving a polymer residue. The viscoelastic surfactant may comprise any viscoelastic surfactant known in the art, any derivative thereof, or any combination thereof. As used herein, the term “viscoelastic surfactant” refers to a surfactant that imparts or is capable of imparting viscoelastic behavior to a fluid due, at least in part, to the association of surfactant molecules to form viscosifying micelles. These viscoelastic surfactants may be cationic, anionic, nonionic, or amphoteric/zwitterionic in nature.
- The viscoelastic surfactants may comprise any number of different compounds, including methyl ester sulfonates (e.g., as described in U.S. patent application Ser. Nos. 11/058,660 (US Patent Publication No. 2006/0180310), 11/058,475 (US Patent Publication No. 2006/0180308), 11/058,612 (US Patent Publication No. 2006/0180309), and 11/058,611 (US Patent Publication No. 20060183646), filed Feb. 15, 2005, each of which is assigned to Halliburton Energy Services, Inc., the relevant disclosures of which are incorporated herein by reference), hydrolyzed keratin (e.g., as described in U.S. Pat. No. 6,547,871 issued Apr. 15, 2003 to Halliburton Energy Services, Inc., the relevant disclosure of which is incorporated herein by reference), sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols (e.g., lauryl alcohol ethoxylate, ethoxylated nonyl phenol), ethoxylated fatty amines, ethoxylated alkyl amines (e.g., cocoalkylamine ethoxylate), betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl betaine), quaternary ammonium compounds (e.g., trimethyltallowammonium chloride, trimethylcocoammonium chloride), derivatives of any of the foregoing, and any combinations of any of the foregoing in any proportion.
- Suitable viscoelastic surfactants may comprise mixtures of several different compounds, including but not limited to: mixtures of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant; and any combination of the foregoing mixtures in any proportion. Examples of suitable mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant are described in U.S. Pat. No. 6,063,738, issued May 16, 2000 to Halliburton Energy Services, Inc., the relevant disclosure of which is incorporated herein by reference. Examples of suitable aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant are described in U.S. Pat. No. 5,897,699, the relevant disclosure of which is incorporated herein by reference. Examples of commercially-available viscoelastic surfactants suitable for use in the present invention may include, but are not limited to, Mirataine BET-O 30™ (an oleamidopropyl betaine surfactant available from Rhodia Inc., Cranbury, N.J.), Aromox APA-T™ (an amine oxide surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethoquad O/12 PG™ (a fatty amine ethoxylate quat surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen T/12™ (a fatty amine ethoxylate surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), Ethomeen S/12™ (a fatty amine ethoxylate surfactant available from Akzo Nobel Chemicals, Chicago, Ill.), and Rewoteric AM TEG™ (a tallow dihydroxyethyl betaine amphoteric surfactant available from Degussa Corp., Parsippany, N.J.).
- According to a preferred embodiment of the invention, the viscosity-increasing agent is at a concentration in the treatment fluid that is at least sufficient to make the viscosity of the treatment fluid greater than water. More preferably, the viscosity-increasing agent is at a concentration in the treatment fluid that is sufficient to make the viscosity of the treatment fluid greater than 5 cP when measured at 511 reciprocal seconds on a Fann 35A model viscometer with a number 1 spring and bob. More preferably, the viscosity-increasing agent is at a concentration in the treatment fluid that is sufficient to make the viscosity of the treatment fluid in the range of 10 cP to 100 cP when measured at 511 reciprocal seconds on a Fann 35A model viscometer with a number 1 spring and bob.
- According to another preferred embodiment according to the invention, the viscosity-increasing polymeric agent is at a concentration of at least 0.05% by weight of the water. More preferably, the viscosity-increasing agent is at a concentration in the range of 0.05% to 10% by weight of the water.
- It is contemplated that it will sometimes be desirable to further increase the viscosity of the treatment fluid. One technique for doing so is to crosslink a polymeric viscosity-increasing agent. According to such an embodiment of the invention, the treatment fluid further comprises a crosslinking agent to crosslink the polymeric material of the viscosity-increasing agent. A multitude of crosslinking agents for such purposes are known in the art. Preferably, the crosslinking agent is selected from the group consisting of: borate releasing compounds, a source of titanium ions, a source of zirconium ions, a source of antimony ions, a source of aluminum ions, a source of periodate ions, a source of permanganate ions, and any combination thereof in any proportion. According to a preferred embodiment, the crosslinking agent is at a concentration of at least 0.025% by weight of the water. According to a more preferred embodiment of the invention, the crosslinking agent is at a concentration in the range of 0.025% to about 1% by weight of the water. When the treatment fluid for use in the methods according to the invention includes a crosslinking agent, it can also be desirable for the treatment fluid to further include a breaker for the crosslinked agent.
- According to another aspect of the invention, the treatment fluid preferably further comprises a breaker adapted to break the viscosity-increasing agent. For example, when the viscosity-increasing agent is polysaccharide based, the breaker is selected to be effective for breaking a polysaccharide-based viscosity-increasing agent. The breaker can be, for example, an enzyme. By way of further example, when the polysaccharide-based viscosity-increasing agent includes starch, the enzyme is selected to be effective for breaking starch. Preferably, an enzyme breaker is at a concentration of at least 0.01 lb per 1000 gal of the water. More preferably, the enzyme breaker is at a concentration in the range of 0.01 lb to 40 lb per 1000 gal of the water. As will be appreciated by persons of skill in the art, however, enzymes are often used as liquid compositions and that the above mentioned values are for fully formulated dry enzyme breakers that typically contain a large percentage of fillers.
- When a breaker is employed for the viscosity-increasing agent, the breaker is at a concentration that is at least sufficient to substantially reduce the viscosity produced by the viscosity producing agent in the treatment fluid. In such case, a preferred embodiment of the method according to the invention includes the steps of allowing time for the breaker to break the viscosity of the treatment fluid and then flowing back the broken fluid from the wellbore.
- For many types of viscosity-increasing agents, the breaker is preferably an oxidizer selected from the group consisting of: a persulfate; a perborate; a bromate; a periodate; a chlorate; a chlorite; a hypochlorite, an organic peroxide; and any combination thereof in any proportion. Further, the breaker is more preferably selected from the group consisting of a lithium, sodium, potassium, or ammonium salt of any of the foregoing, and any combination thereof in any proportion. The oxidizing breaker for breaking a viscosity-increasing agent internal to the treatment fluid is preferably at a concentration of at least 0.01 lb per 1000 gal of the water. More preferably, such a breaker is at a concentration in the range of 0.1 to 200 per 1000 gal of the water.
- It is contemplated that in some applications of the methods according to the invention, it may be desirable that the breaker be a delayed release breaker. One technique for making a delayed breaker is to coat or encapsulate the breaker to delay the release of the breaker into the water. Another technique is to generate the breaker in situ over time or upon a change in pH of the treatment fluid.
- According to a preferred embodiment of the invention, the method further includes the step of: after introducing the treatment fluid into the wellbore, allowing the viscosity of the treatment fluid to break to a substantially lower viscosity fluid while down hole. According to a further preferred embodiment, the method further comprises the step of: after allowing the viscosity of the treatment fluid to break, flowing the fluid back from the well.
- According to further embodiments of the methods of the invention, the treatment fluid can further comprise a breaker to be carried by the treatment fluid into the wellbore for breaking a viscosity-increasing agent that is external of the treatment fluid. According to these embodiments, the breaker for the viscosity-increasing agent in the treatment fluid is preferably at a concentration in an external aqueous fluid that is at least sufficient to substantially break the viscosity of the treatment fluid. The breaker for a viscosity-increasing agent that is external to the treatment fluid can be the same or different than the breaker for the viscosity-increasing agent in the treatment fluid. The additional or different breaker for breaking a viscosity-increasing agent external to the treatment fluid is preferably at a concentration of at least 0.01 lb per 1000 gal of the water. More preferably, the breaker is at a concentration in the range of 0.1 lb to 200 lb per 1000 gal of the water.
- It is contemplated that the methods according to the invention can include foaming of the treatment fluid. According to these embodiments, the treatment fluid further comprises: an additive for foaming. The treatment fluid may be formed at a remote location and provided to the well site for the treatment method, or it can be formed locally at the well site. The treatment fluid preferably further comprises: a sufficient gas to form a foam. As used herein, foam also refers to commingled fluids. Preferably, the gas would be mixed with the other constituents of the treatment fluid at the well site to form a foamed or co-mingled fluid. According to a preferred embodiment of the invention, the gas is selected from the group consisting of: air, CO2, nitrogen, and any combination thereof in any proportion. In applications of the method utilizing a gas, typically, the gas is at a concentration in the range of 5% to 95% by volume of the water.
- According to one aspect of the methods of the invention, the step of introducing the treatment fluid into the wellbore further comprises: introducing the treatment fluid at a rate and pressure below the fracture gradient of the subterranean formation. According to a further embodiment, the treatment fluid is applied such that the treatment fluid is introduced such that the proppant pack of a previously generated fracture or gravel pack is treated.
- As will be appreciated by those of skill in the art, in the context of using a method according to the invention to treat a portion of the subterranean formation surrounding a wellbore, the permeability of the matrix of the surrounding formation would be expected to be relatively high. According to a further embodiment, the treatment fluid is applied such that the portion of the subterranean formation is a portion surrounding the wellbore, and wherein the treatment fluid is introduced such that the portion surrounding the wellbore is expected to be saturated to a depth of at least 1 foot. More preferably, the treatment fluid is applied such that the portion surrounding the wellbore is expected to be saturated to a depth in the range of 1 foot to 3 feet. Of course, it is recognized that desired or expected depth of penetration into the surrounding matrix of the formation will not necessarily be perfectly uniform. It is also recognized that the parameters for designing a treatment for a desired or expected depth of penetration are well known in the art, including, for example, the length of the wellbore to be treated and the volume of treatment fluid injected into the wellbore. One skilled in the art will recognize that a deeper penetration may be desired or obtained in formations with higher permeability.
- In some situations, the permeability of the matrix of the surrounding formation would be expected to be relatively low. According to another embodiment, the portion of the subterranean formation is an area surrounding a fracture extending into the formation, and the treatment fluid is introduced such that the surrounding area is expected to be saturated to a depth of at least 0.1 inches. More preferably, the treatment fluid is introduced into the wellbore under conditions such that the area surrounding the fracture is expected to be saturated to a depth in the range of 0.1 inches to 2 inches. One skilled in the art will recognize that a deeper penetration may be desired or obtained in formations with higher permeability.
- According to another embodiment, the portion of the subterranean formation is a perforation tunnel, and the treatment fluid is introduced such that the perforation tunnel and the surrounding area is expected to be saturated to a depth of at least 0.1 inches. More preferably, the treatment fluid is introduced into the wellbore under conditions such that the area surrounding the perforation tunnel is expected to be saturated to a depth in the range of 0.1 inches to 2 inches. One skilled in the art will recognize that a deeper penetration may be desired or obtained in formations with higher permeability.
- One of skill in the art will further recognize that for the purpose of treating the matrix of a proppant pack in a pre-existing gravel pack, fracture, or perforation, it may not be necessary or desirable to penetrate into the matrix of the surrounding formation.
- According to another aspect of the methods of the invention, the methods further comprise the step of: after the step of introducing the treatment fluid, introducing a non-viscosified treatment fluid into the wellbore, wherein the non-viscosified treatment fluid comprises: water and a chelating agent, without any substantial concentration of any viscosity-increasing agent. According to this aspect, the viscosified treatment fluid is capable of moving into zones of the subterranean formation that have relatively higher permeability, thereby diverting the non-viscosified treatment fluid into zones of the subterranean formation that have relatively lower permeability. According to this aspect, the injection pressure is preferably maintained from the step of introducing the treatment fluid to the step of introducing the non-viscosified treatment fluid.
- According to yet another aspect of the methods of the invention, the methods further comprise the step of: applying an afterflush fluid to the portion of the subterranean formation. For example, the afterflush fluid can comprise: water, a gas, a brine, a hydrocarbon, or a mixture thereof.
- An example of a treatment fluid for use in the methods according to the invention was formed as shown in the following Table 1:
-
TABLE 1 Component Per 200 ml Per 1000 gallons Water 157.6 ml 788 US gals H4EDTA 98% 46.61 g 1987 lbs Potassium 20.95 g 870 lbs Hydroxide Solid 96% Xanthan 0.96 g 40 lb/Mgal - The rheological properties of the example composition were measured on a Fann Model 35 A viscometer as shown in the following Table 2:
-
TABLE 2 300 rpm 600 rpm Dial Reading at room temperature 21 29 Dial Reading at room temperature 29 35 after 4 hours at 175° F. - Therefore, the methods of the present invention are well adapted to carry out the objects and attain the ends and advantages mentioned as well as those that are inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims.
Claims (23)
1. A method for treating a portion of a subterranean formation or a proppant pack, the method comprising the steps of:
(A) forming or providing a treatment fluid comprising:
(i) water;
(ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions; and
(iii) a viscosity-increasing agent, wherein the viscosity-increasing agent comprises a viscoelastic surfactant; and
(B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the matrix of the formation or the proppant pack.
2. The method according to claim 1 , wherein the pH of the treatment fluid is equal to or greater than 2.
3. The method according to claim 1 , wherein the pH of the treatment fluid is equal to or greater than 5.
4. The method according to claim 1 , wherein the pH of the treatment fluid is in the range of 6-12.
5. The method according to claim 1 , wherein the chelating agent is effective for chelating at least calcium ions.
6. The method according to claim 1 , wherein the chelating agent is soluble in distilled water at standard temperature and pressure at a concentration of at least 0.2 mole-equivalent for calcium ions per liter of the distilled water.
7. The method according to claim 6 , wherein a test solution of the chelating agent at a concentration of 0.2 mole-equivalent for calcium ions per liter of the distilled water is effective for chelating at least 0.1 mole calcium ions from calcium carbonate per liter.
8. The method according to claim 7 , wherein prior to exposing the test solution of the chelating agent to the calcium carbonate, the test solution is adjusted to have a pH in the range of 5-6.
9. The method according to claim 1 , wherein the chelating agent is selected from the group consisting of ethylenediamine tetraacetic acid (“EDTA”), nitrilotriacetic acid (“NTA”), hydroxyethylethylenediaminetriacetic acid (“HEDTA”), diethylenetriaminepentaacetic acid (“DTPA”), propylenediaminetetraacetic acid (“PDTA”), ethylenediaminedi(o-hydroxyphenylacetic) acid (“EDDHA”), a sodium or potassium salt of any of the foregoing, dicarboxymethyl glutamic acid tetrasodium salt (“GLDA”), a derivative of any of the foregoing, or any combination of any of the foregoing in any proportion.
10. The method according to claim 1 , wherein chelating agent is at a concentration in the range of 1 to 80% by weight of the water.
11. The method according to claim 1 , wherein the viscoelastic surfactant is selected from the group consisting of: methyl ester sulfonates, sulfosuccinates, taurates, amine oxides, ethoxylated amides, alkoxylated fatty acids, alkoxylated alcohols, lauryl alcohol ethoxylate, ethoxylated nonyl phenol, ethoxylated fatty amines, ethoxylated alkyl amines, cocoalkylamine ethoxylate, betaines, modified betaines, alkylamidobetaines, cocoamidopropyl betaine, quaternary ammonium compounds, trimethyltallowammonium chloride, trimethylcocoammonium chloride, an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl dimethylamine oxide, cocoamidopropyl hydroxysultaine, tallow dihydroxyethyl betaine, derivatives of any of the foregoing, and any combination of the foregoing in any proportion.
12. The method according to claim 1 , wherein the viscosity-increasing agent is at a concentration in the treatment fluid that is at least sufficient to make the viscosity of the treatment fluid greater than 5 cP when measured at 511 reciprocal seconds on a Fann 35A model viscometer with a number 1 spring and bob.
13. The method according to claim 1 , wherein the viscosity-increasing agent is at a concentration in the range of 0.05% to 10% by weight of the water.
14. The method according to claim 1 , wherein the treatment fluid further comprises a breaker adapted to break the viscosity-increasing agent.
15. The method according to claim 14 , further comprising the step of: after introducing the treatment fluid into the wellbore, allowing the viscosity of the treatment fluid to break to while down hole.
16. The method according to claim 1 , wherein the treatment fluid further comprises a breaker to be carried by the treatment fluid into the wellbore for breaking a viscosity-increasing agent that is external of the treatment fluid.
17. The method according to claim 1 , wherein the treatment fluid further comprises:
an additive for foaming.
18. The method according to claim 1 , wherein the step of introducing the treatment fluid into the wellbore further comprises:
introducing the treatment fluid at a rate and pressure below the fracture gradient of the subterranean formation.
19. The method according to claim 18 , wherein the portion to be treated is a portion of the subterranean formation surrounding the wellbore, and wherein the treatment fluid is introduced such that the portion of the formation surrounding the wellbore is expected to be saturated to a depth of at least 1 foot.
20. The method according to claim 18 , wherein the portion to be treated is a portion of the subterranean formation surrounding a pre-existing fracture extending into the formation, and wherein the treatment fluid is introduced such that the portion of the subterranean formation surrounding the pre-existing fracture is expected to be saturated to a depth of at least 0.1 inches.
21. The method according to claim 1 , further comprising the step of: after the step of introducing the treatment fluid, introducing a non-viscosified treatment fluid into the wellbore, wherein the non-viscosified treatment fluid comprises: water and a chelating agent, without any concentration of any viscosity-increasing agent.
22. The method according to claim 21 , wherein the injection pressure is maintained from the step of introducing the treatment fluid to the step of introducing the non-viscosified treatment fluid.
23. A method for treating a portion of a subterranean formation or a proppant pack, the method comprising the steps of:
(A) forming or providing a treatment fluid comprising:
(i) water;
(ii) a chelating agent capable of forming a heterocyclic ring that contains a metal ion attached to at least two nonmetal ions, wherein the chelating agent is effective for chelating at least calcium ions, and wherein chelating agent is at a concentration in the range of 1% to 80% by weight of the water; and
(iii) a viscosity-increasing agent, wherein the viscosity-increasing agent comprises a viscoelastic surfactant;
wherein the pH of the treatment fluid is equal to or greater than 5; and
(B) introducing the treatment fluid into the wellbore under sufficient pressure to force the treatment fluid into the formation or the proppant pack, wherein the portion to be treated is a portion of the subterranean formation surrounding a pre-existing fracture extending into the formation, and wherein the treatment fluid is introduced such that the portion of the subterranean formation surrounding the pre-existing fracture is expected to be saturated to a depth of at least 0.1 inches.
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US13/433,511 US20120186811A1 (en) | 2007-05-10 | 2012-03-29 | Methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove calcium carbonate and similar materials from the matrix of a formation or a proppant pack |
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US13/433,511 Abandoned US20120186811A1 (en) | 2007-05-10 | 2012-03-29 | Methods for stimulating oil or gas production using a viscosified aqueous fluid with a chelating agent to remove calcium carbonate and similar materials from the matrix of a formation or a proppant pack |
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US13/611,674 Abandoned US20130000902A1 (en) | 2007-05-10 | 2012-09-12 | Methods for Stimulating Oil or Gas Production Using a Viscosified Aqueous Fluid with a Chelating Agent to Remove Calcium Carbonate and Similar Materials from the Matrix of a Formation or a Proppant Pack |
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Also Published As
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US20130000913A1 (en) | 2013-01-03 |
US20080277112A1 (en) | 2008-11-13 |
US20130000902A1 (en) | 2013-01-03 |
US20130000901A1 (en) | 2013-01-03 |
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