US20150330199A1 - Method for enhancing acidizing treatment of a formation having a high bottom hole temperature - Google Patents
Method for enhancing acidizing treatment of a formation having a high bottom hole temperature Download PDFInfo
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- US20150330199A1 US20150330199A1 US14/278,550 US201414278550A US2015330199A1 US 20150330199 A1 US20150330199 A1 US 20150330199A1 US 201414278550 A US201414278550 A US 201414278550A US 2015330199 A1 US2015330199 A1 US 2015330199A1
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- Prior art keywords
- acid
- acids
- alkali metal
- concentration
- combinations
- Prior art date
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Links
- 230000015572 biosynthetic process Effects 0.000 title claims abstract description 66
- 238000000034 method Methods 0.000 title claims abstract description 50
- 238000011282 treatment Methods 0.000 title description 11
- 230000002708 enhancing effect Effects 0.000 title description 4
- -1 glutamic acid N Chemical class 0.000 claims abstract description 97
- 238000005755 formation reaction Methods 0.000 claims abstract description 65
- KXDHJXZQYSOELW-UHFFFAOYSA-N Carbamic acid Chemical class NC(O)=O KXDHJXZQYSOELW-UHFFFAOYSA-N 0.000 claims abstract description 64
- 150000001735 carboxylic acids Chemical class 0.000 claims abstract description 51
- 230000035699 permeability Effects 0.000 claims abstract description 45
- 235000019738 Limestone Nutrition 0.000 claims abstract description 12
- 239000006028 limestone Substances 0.000 claims abstract description 12
- 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 abstract description 10
- 150000001991 dicarboxylic acids Chemical class 0.000 claims abstract description 10
- 229960003330 pentetic acid Drugs 0.000 claims abstract description 10
- WHUUTDBJXJRKMK-UHFFFAOYSA-N Glutamic acid Natural products OC(=O)C(N)CCC(O)=O WHUUTDBJXJRKMK-UHFFFAOYSA-N 0.000 claims abstract description 4
- 235000013922 glutamic acid Nutrition 0.000 claims abstract description 4
- 239000004220 glutamic acid Substances 0.000 claims abstract description 4
- 108010077895 Sarcosine Proteins 0.000 claims abstract description 3
- FSYKKLYZXJSNPZ-UHFFFAOYSA-N sarcosine Chemical compound C[NH2+]CC([O-])=O FSYKKLYZXJSNPZ-UHFFFAOYSA-N 0.000 claims abstract description 3
- 239000002253 acid Substances 0.000 claims description 148
- 229910052783 alkali metal Inorganic materials 0.000 claims description 46
- 150000007513 acids Chemical class 0.000 claims description 23
- 150000001732 carboxylic acid derivatives Chemical class 0.000 claims description 20
- 239000002585 base Substances 0.000 claims description 17
- 230000001965 increasing effect Effects 0.000 claims description 15
- OFOBLEOULBTSOW-UHFFFAOYSA-N Malonic acid Chemical compound OC(=O)CC(O)=O OFOBLEOULBTSOW-UHFFFAOYSA-N 0.000 claims description 9
- KRKNYBCHXYNGOX-UHFFFAOYSA-N citric acid Chemical compound OC(=O)CC(O)(C(O)=O)CC(O)=O KRKNYBCHXYNGOX-UHFFFAOYSA-N 0.000 claims description 6
- 229910052757 nitrogen Inorganic materials 0.000 claims description 6
- 150000003839 salts Chemical class 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
- 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
- VGGSQFUCUMXWEO-UHFFFAOYSA-N Ethene Chemical compound C=C VGGSQFUCUMXWEO-UHFFFAOYSA-N 0.000 claims description 4
- 239000005977 Ethylene Substances 0.000 claims description 4
- JYXGIOKAKDAARW-UHFFFAOYSA-N N-(2-hydroxyethyl)iminodiacetic acid Chemical compound OCCN(CC(O)=O)CC(O)=O JYXGIOKAKDAARW-UHFFFAOYSA-N 0.000 claims description 4
- WNLRTRBMVRJNCN-UHFFFAOYSA-N adipic acid Chemical compound OC(=O)CCCCC(O)=O WNLRTRBMVRJNCN-UHFFFAOYSA-N 0.000 claims description 4
- 229960001484 edetic acid Drugs 0.000 claims description 4
- 150000004679 hydroxides Chemical class 0.000 claims description 4
- JVTAAEKCZFNVCJ-UHFFFAOYSA-N lactic acid Chemical compound CC(O)C(O)=O JVTAAEKCZFNVCJ-UHFFFAOYSA-N 0.000 claims description 4
- KDYFGRWQOYBRFD-UHFFFAOYSA-N succinic acid Chemical compound OC(=O)CCC(O)=O KDYFGRWQOYBRFD-UHFFFAOYSA-N 0.000 claims description 4
- RGHNJXZEOKUKBD-SQOUGZDYSA-N Gluconic acid Natural products OC[C@@H](O)[C@@H](O)[C@H](O)[C@@H](O)C(O)=O RGHNJXZEOKUKBD-SQOUGZDYSA-N 0.000 claims description 3
- BJEPYKJPYRNKOW-REOHCLBHSA-N (S)-malic acid Chemical compound OC(=O)[C@@H](O)CC(O)=O BJEPYKJPYRNKOW-REOHCLBHSA-N 0.000 claims description 2
- RTBFRGCFXZNCOE-UHFFFAOYSA-N 1-methylsulfonylpiperidin-4-one Chemical compound CS(=O)(=O)N1CCC(=O)CC1 RTBFRGCFXZNCOE-UHFFFAOYSA-N 0.000 claims description 2
- FCKYPQBAHLOOJQ-UHFFFAOYSA-N Cyclohexane-1,2-diaminetetraacetic acid Chemical compound OC(=O)CN(CC(O)=O)C1CCCCC1N(CC(O)=O)CC(O)=O FCKYPQBAHLOOJQ-UHFFFAOYSA-N 0.000 claims description 2
- RGHNJXZEOKUKBD-UHFFFAOYSA-N D-gluconic acid Natural products OCC(O)C(O)C(O)C(O)C(O)=O RGHNJXZEOKUKBD-UHFFFAOYSA-N 0.000 claims description 2
- FEWJPZIEWOKRBE-UHFFFAOYSA-N Tartaric acid Natural products [H+].[H+].[O-]C(=O)C(O)C(O)C([O-])=O FEWJPZIEWOKRBE-UHFFFAOYSA-N 0.000 claims description 2
- ZMZINYUKVRMNTG-UHFFFAOYSA-N acetic acid;formic acid Chemical compound OC=O.CC(O)=O ZMZINYUKVRMNTG-UHFFFAOYSA-N 0.000 claims description 2
- 239000001361 adipic acid Substances 0.000 claims description 2
- 235000011037 adipic acid Nutrition 0.000 claims description 2
- BJEPYKJPYRNKOW-UHFFFAOYSA-N alpha-hydroxysuccinic acid Natural products OC(=O)C(O)CC(O)=O BJEPYKJPYRNKOW-UHFFFAOYSA-N 0.000 claims description 2
- JFCQEDHGNNZCLN-UHFFFAOYSA-N anhydrous glutaric acid Natural products OC(=O)CCCC(O)=O JFCQEDHGNNZCLN-UHFFFAOYSA-N 0.000 claims description 2
- 239000000174 gluconic acid Substances 0.000 claims description 2
- 235000012208 gluconic acid Nutrition 0.000 claims description 2
- 125000004464 hydroxyphenyl group Chemical group 0.000 claims description 2
- 239000004310 lactic acid Substances 0.000 claims description 2
- 235000014655 lactic acid Nutrition 0.000 claims description 2
- 239000001630 malic acid Substances 0.000 claims description 2
- 235000011090 malic acid Nutrition 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
- WSHYKIAQCMIPTB-UHFFFAOYSA-M potassium;2-oxo-3-(3-oxo-1-phenylbutyl)chromen-4-olate Chemical compound [K+].[O-]C=1C2=CC=CC=C2OC(=O)C=1C(CC(=O)C)C1=CC=CC=C1 WSHYKIAQCMIPTB-UHFFFAOYSA-M 0.000 claims description 2
- 239000001509 sodium citrate Substances 0.000 claims description 2
- NLJMYIDDQXHKNR-UHFFFAOYSA-K sodium citrate Chemical compound O.O.[Na+].[Na+].[Na+].[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O NLJMYIDDQXHKNR-UHFFFAOYSA-K 0.000 claims description 2
- 239000001384 succinic acid Substances 0.000 claims description 2
- 235000002906 tartaric acid Nutrition 0.000 claims description 2
- 239000011975 tartaric acid Substances 0.000 claims description 2
- 238000002347 injection Methods 0.000 abstract description 27
- 239000007924 injection Substances 0.000 abstract description 27
- 150000007524 organic acids Chemical class 0.000 abstract description 5
- 239000011148 porous material Substances 0.000 description 12
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 11
- 239000011575 calcium Substances 0.000 description 10
- 230000001186 cumulative effect Effects 0.000 description 9
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 8
- 239000003929 acidic solution Substances 0.000 description 8
- 229910052791 calcium Inorganic materials 0.000 description 8
- 239000011159 matrix material Substances 0.000 description 8
- 239000012530 fluid Substances 0.000 description 7
- XEEYBQQBJWHFJM-UHFFFAOYSA-N Iron Chemical compound [Fe] XEEYBQQBJWHFJM-UHFFFAOYSA-N 0.000 description 6
- 230000007797 corrosion Effects 0.000 description 6
- 238000005260 corrosion Methods 0.000 description 6
- 239000007789 gas Substances 0.000 description 6
- 239000000203 mixture Substances 0.000 description 6
- 230000000694 effects Effects 0.000 description 5
- 238000004519 manufacturing process Methods 0.000 description 5
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 4
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 4
- 239000011149 active material Substances 0.000 description 4
- 230000008901 benefit Effects 0.000 description 4
- 238000002591 computed tomography Methods 0.000 description 4
- 230000009467 reduction Effects 0.000 description 4
- 230000000638 stimulation Effects 0.000 description 4
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 description 3
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 3
- 239000003795 chemical substances by application Substances 0.000 description 3
- 229930195733 hydrocarbon Natural products 0.000 description 3
- 150000002430 hydrocarbons Chemical class 0.000 description 3
- 239000003112 inhibitor Substances 0.000 description 3
- 229910052500 inorganic mineral Inorganic materials 0.000 description 3
- 229910052742 iron Inorganic materials 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 229910052751 metal Inorganic materials 0.000 description 3
- 239000002184 metal Substances 0.000 description 3
- 239000011707 mineral Substances 0.000 description 3
- 235000005985 organic acids Nutrition 0.000 description 3
- 239000004094 surface-active agent Substances 0.000 description 3
- 239000004215 Carbon black (E152) Substances 0.000 description 2
- KRHYYFGTRYWZRS-UHFFFAOYSA-N Fluorane Chemical compound F KRHYYFGTRYWZRS-UHFFFAOYSA-N 0.000 description 2
- NBIIXXVUZAFLBC-UHFFFAOYSA-N Phosphoric acid Chemical compound OP(O)(O)=O NBIIXXVUZAFLBC-UHFFFAOYSA-N 0.000 description 2
- QAOWNCQODCNURD-UHFFFAOYSA-N Sulfuric acid Chemical compound OS(O)(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-N 0.000 description 2
- 229910000323 aluminium silicate Inorganic materials 0.000 description 2
- 229910000019 calcium carbonate Inorganic materials 0.000 description 2
- 239000013522 chelant Substances 0.000 description 2
- 239000000839 emulsion Substances 0.000 description 2
- 239000004088 foaming agent Substances 0.000 description 2
- IXCSERBJSXMMFS-UHFFFAOYSA-N hcl hcl Chemical compound Cl.Cl IXCSERBJSXMMFS-UHFFFAOYSA-N 0.000 description 2
- XLYOFNOQVPJJNP-UHFFFAOYSA-M hydroxide Chemical compound [OH-] XLYOFNOQVPJJNP-UHFFFAOYSA-M 0.000 description 2
- 238000002354 inductively-coupled plasma atomic emission spectroscopy Methods 0.000 description 2
- 229920000642 polymer Polymers 0.000 description 2
- 239000000243 solution Substances 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- BMYNFMYTOJXKLE-UHFFFAOYSA-N 3-azaniumyl-2-hydroxypropanoate Chemical compound NCC(O)C(O)=O BMYNFMYTOJXKLE-UHFFFAOYSA-N 0.000 description 1
- 241000894006 Bacteria Species 0.000 description 1
- 229910021532 Calcite Inorganic materials 0.000 description 1
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 1
- 244000007835 Cyamopsis tetragonoloba Species 0.000 description 1
- GRYLNZFGIOXLOG-UHFFFAOYSA-N Nitric acid Chemical compound O[N+]([O-])=O GRYLNZFGIOXLOG-UHFFFAOYSA-N 0.000 description 1
- 239000000654 additive Substances 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- 229910000147 aluminium phosphate Inorganic materials 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 229910000512 ankerite Inorganic materials 0.000 description 1
- 230000003466 anti-cipated effect Effects 0.000 description 1
- 239000003125 aqueous solvent Substances 0.000 description 1
- KGBXLFKZBHKPEV-UHFFFAOYSA-N boric acid Chemical compound OB(O)O KGBXLFKZBHKPEV-UHFFFAOYSA-N 0.000 description 1
- 239000004327 boric acid Substances 0.000 description 1
- 239000000920 calcium hydroxide Substances 0.000 description 1
- 229910001861 calcium hydroxide Inorganic materials 0.000 description 1
- BRPQOXSCLDDYGP-UHFFFAOYSA-N calcium oxide Chemical compound [O-2].[Ca+2] BRPQOXSCLDDYGP-UHFFFAOYSA-N 0.000 description 1
- 239000000292 calcium oxide Substances 0.000 description 1
- ODINCKMPIJJUCX-UHFFFAOYSA-N calcium oxide Inorganic materials [Ca]=O ODINCKMPIJJUCX-UHFFFAOYSA-N 0.000 description 1
- 125000005587 carbonate group Chemical group 0.000 description 1
- 150000004649 carbonic acid derivatives Chemical class 0.000 description 1
- 230000009920 chelation Effects 0.000 description 1
- 238000006243 chemical reaction Methods 0.000 description 1
- 239000004927 clay Substances 0.000 description 1
- 239000000470 constituent Substances 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 238000013461 design Methods 0.000 description 1
- 239000010459 dolomite Substances 0.000 description 1
- 229910000514 dolomite Inorganic materials 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000003480 eluent Substances 0.000 description 1
- 238000002474 experimental method Methods 0.000 description 1
- 239000010433 feldspar Substances 0.000 description 1
- 239000000706 filtrate Substances 0.000 description 1
- 238000007429 general method Methods 0.000 description 1
- 150000004676 glycans Chemical class 0.000 description 1
- 239000011019 hematite Substances 0.000 description 1
- 229910052595 hematite Inorganic materials 0.000 description 1
- 235000011167 hydrochloric acid Nutrition 0.000 description 1
- 229910052900 illite Inorganic materials 0.000 description 1
- 238000010348 incorporation Methods 0.000 description 1
- 230000009545 invasion Effects 0.000 description 1
- 238000011835 investigation Methods 0.000 description 1
- LIKBJVNGSGBSGK-UHFFFAOYSA-N iron(3+);oxygen(2-) Chemical compound [O-2].[O-2].[O-2].[Fe+3].[Fe+3] LIKBJVNGSGBSGK-UHFFFAOYSA-N 0.000 description 1
- 229910052622 kaolinite Inorganic materials 0.000 description 1
- CYPPCCJJKNISFK-UHFFFAOYSA-J kaolinite Chemical compound [OH-].[OH-].[OH-].[OH-].[Al+3].[Al+3].[O-][Si](=O)O[Si]([O-])=O CYPPCCJJKNISFK-UHFFFAOYSA-J 0.000 description 1
- 239000000347 magnesium hydroxide Substances 0.000 description 1
- 229910001862 magnesium hydroxide Inorganic materials 0.000 description 1
- 239000000395 magnesium oxide Substances 0.000 description 1
- CPLXHLVBOLITMK-UHFFFAOYSA-N magnesium oxide Inorganic materials [Mg]=O CPLXHLVBOLITMK-UHFFFAOYSA-N 0.000 description 1
- AXZKOIWUVFPNLO-UHFFFAOYSA-N magnesium;oxygen(2-) Chemical compound [O-2].[Mg+2] AXZKOIWUVFPNLO-UHFFFAOYSA-N 0.000 description 1
- 238000012986 modification Methods 0.000 description 1
- 230000004048 modification Effects 0.000 description 1
- 150000002763 monocarboxylic acids Chemical class 0.000 description 1
- 229910017604 nitric acid Inorganic materials 0.000 description 1
- VGIBGUSAECPPNB-UHFFFAOYSA-L nonaaluminum;magnesium;tripotassium;1,3-dioxido-2,4,5-trioxa-1,3-disilabicyclo[1.1.1]pentane;iron(2+);oxygen(2-);fluoride;hydroxide Chemical compound [OH-].[O-2].[O-2].[O-2].[O-2].[O-2].[F-].[Mg+2].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[Al+3].[K+].[K+].[K+].[Fe+2].O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2.O1[Si]2([O-])O[Si]1([O-])O2 VGIBGUSAECPPNB-UHFFFAOYSA-L 0.000 description 1
- 230000000737 periodic effect Effects 0.000 description 1
- 229920002401 polyacrylamide Polymers 0.000 description 1
- 229920001282 polysaccharide Polymers 0.000 description 1
- 239000005017 polysaccharide Substances 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 239000011028 pyrite Substances 0.000 description 1
- NIFIFKQPDTWWGU-UHFFFAOYSA-N pyrite Chemical compound [Fe+2].[S-][S-] NIFIFKQPDTWWGU-UHFFFAOYSA-N 0.000 description 1
- 229910052683 pyrite Inorganic materials 0.000 description 1
- 239000010453 quartz Substances 0.000 description 1
- 125000001453 quaternary ammonium group Chemical group 0.000 description 1
- 230000009257 reactivity Effects 0.000 description 1
- 238000011084 recovery Methods 0.000 description 1
- 238000011160 research Methods 0.000 description 1
- VYPSYNLAJGMNEJ-UHFFFAOYSA-N silicon dioxide Inorganic materials O=[Si]=O VYPSYNLAJGMNEJ-UHFFFAOYSA-N 0.000 description 1
- 239000002195 soluble material Substances 0.000 description 1
- 239000002904 solvent Substances 0.000 description 1
- 239000000126 substance Substances 0.000 description 1
- 229920001059 synthetic polymer Polymers 0.000 description 1
- 239000010457 zeolite Substances 0.000 description 1
Images
Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/28—Dissolving minerals other than hydrocarbons, e.g. by an alkaline or acid leaching agent
-
- 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
- C09K8/62—Compositions for forming crevices or fractures
- C09K8/72—Eroding chemicals, e.g. acids
-
- 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
- C09K8/54—Compositions for in situ inhibition of corrosion in boreholes or wells
Definitions
- the present invention relates to methods and compositions for enhancing the acidizing treatment of subterranean formations, and more particularly to methods and compositions for using carboxylic acids and/or aminocarboxylic acids to create wormholes.
- Such treatments use aqueous acidic solutions and are commonly carried out in hydrocarbon-containing subterranean formations to accomplish a number of purposes, one of which is to increase the permeability of the formation or by-pass near well bore damage.
- the increase in formation permeability normally results in an increase in the recovery of hydrocarbons from the formation.
- aqueous acidic solutions are introduced into the subterranean formation under pressure so that the acidic solution flows into the pore spaces of the formation.
- sandstone formations which contain siliceous materials like quartz as the major constituent and which in addition may contain various amounts of clays (aluminosilicates such as kaolinite or illite) or alkaline aluminosilicates such as feldspars, and zeolites, as well as carbonates (calcite, dolomite, ankerite) and iron-based minerals (hematite and pyrite).
- clays aluminosilicates such as kaolinite or illite
- alkaline aluminosilicates such as feldspars
- zeolites as well as carbonates (calcite, dolomite, ankerite) and iron-based minerals (hematite and pyrite).
- carbonates calcite, dolomite, ankerite
- iron-based minerals hematit
- the acidic solution reacts with acid-soluble materials contained in the sandstone or limestone formation which results in an increase in the size of the pore spaces and an increase in the permeability of the formation.
- one or more fractures are produced in the formation and the acidic solution is introduced into the fracture to etch flow channels in the fracture face.
- the acid also enlarges the pore spaces in the fracture face and in the formation.
- the rate at which acidizing fluids react with reactive materials in the subterranean formation is a function of various factors including but not limited to acid concentration, temperature, fluid velocity and the type of reactive material encountered. Whatever the rate of reaction of the acidic solution, the solution can be introduced into the formation only a certain distance before it becomes spent. It is desirable to maintain the acidic solution in a reactive condition for as long a period of time as possible to maximize the permeability enhancement produced by the acidic solution.
- acids downhole is not without problems.
- One such problem is that the acids, in addition to increasing the permeability of a hydrocarbon bearing formation, may also cause excessive corrosion of the downhole metal equipment. Anything made of metal in contact with the acid may be subject to such excessive corrosion.
- a method for acidizing a subterranean formation involves injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume.
- the method further involves subsequently injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume.
- the steps are modified by the first step differing from the second step by at least one of the following parameters:
- FIG. 1 is a schematic, cross-section illustration of a wellbore and stimulation zones around the wellbore after acid injection;
- FIG. 2 is a theoretical graph of skin factor as a function of damaged zone permeability illustrating the effect of increasing the permeability in the damaged zone on the skin factor, where the original formation permeability is 100 md, while the damaged permeability is 5 md;
- FIG. 3 is a theoretical graph of skin factor as a function of zone radius illustrating the effect of increasing the damaged zone radius on the skin factor, where the original formation permeability is 100 md, where the damaged permeability is originally 5 md but has been stimulated to be 1000 md;
- FIG. 4 is a series of photographs of limestone cores before and after injection of GLDA
- FIG. 5 is a graph of pressure drop across the core as a function of cumulative pore volume at an injection rate of 1 cc/min, 300° F. (149° C.), and 5 gpt (or liters per thousand liters) of CI-111 corrosion inhibitor;
- FIG. 6 is a plot of calcium (Ca in mg) as a function of cumulative pore volume (PV) for 50% vol/vol STIMCARBTM-GLDA (20 wt % active) compared to 25% vol/vol STIMCARBTM-GLDA (10 wt % active);
- FIG. 7 is a plot of cumulative calcium (Ca in mg) as a function of cumulative pore volume (PV) for 50% vol/vol STIMCARBTM-GLDA (20 wt % active) compared to 25% vol/vol StimCarb-GLDA (10 wt % active);
- FIG. 8 are CT-Scan images showing worm-hole distribution for a limestone core treated with 25% vol/vol STIMCARBTM-GLDA.
- FIG. 9 are CT-Scan images showing worm-hole distribution for a limestone core treated with 50% vol/vol STIMCARBTM-GLDA.
- FIG. 1 is a schematic illustration which is not necessarily to scale and that certain features are exaggerated for clarity, and thus the methods and apparatus described herein should not be limited by the drawings.
- GLDA glutamic acid N,N-diacetic acid
- HCl hydrochloric acid
- Other benefits include the incorporation of chelation chemistry, enabling it to function as an effective iron control agent (that is, the GLDA also functions as a chelant), and provide better tubular protection even at higher temperatures (is less corrosive), compared to conventional acid systems, as well as biodegradability.
- carboxylic acid encompasses monocarboxylic acids, dicarboxylic acids and polycarboxylic acids. Further, as defined herein, “aminocarboxylic acid” encompasses aminomonocarboxylic acids, aminodicarboxylic acids and aminopolycarboxylic acids
- Carboxylic or aminocarboxylic acid are retarded acids. Recent experimental work discovered that reducing concentration or pH of dicarboxylic or aminocarboxylic acid can result in local permeability enhancement rather than the wormhole creation. Also, it has been discovered that reducing the active material concentration and injecting a larger volume of diluted dicarboxylic or aminocarboxylic acid results in a lower skin factor because of increased unreacted acid in the flushed zone; for instance, see zone 3 in FIG. 1 .
- Skin factor is a dimensionless numerical value used to analytically model the difference from the pressure drop predicted by Darcy's law due to skin (zone of reduced permeability immediately around a wellbore). Typical skin factor values range from ⁇ 6 for an infinite conductivity massive hydraulic fracture to more than 100 for a poorly executed gravel pack.
- skin refers to a damaged zone, which is zone 2 in FIG. 1 , and may include zone 3 .
- the initial skin factor is positive for zone 2 , while it is zero for zone 3 .
- the skin factor will be negative for both zones (zones 2 and 3 ). This will improve production as compared to previous techniques where only the skin factor of zone 2 was reduced.
- one advantage of the method described herein is that the permeability may be increased and the skin in zone 3 is reduced, in addition to which production is increased.
- Zone 2 of FIG. 1 schematically indicates the wormholes 10 stimulated in the zone by the HCl.
- HCl does not stimulate the rest of the formation since typically all of the HCl is consumed (spent) to create the wormholes 10 . Therefore, even in zone 1 , the matrix around the wormholes 10 still has damaged permeability.
- Zone 3 represents the flushed zone containing neutralized HCl utilized for wormhole 10 creation.
- the permeability of the flushed zone is dependent on the wormhole 10 length. If the wormhole 10 length is greater than the damaged radius then the flushed zone permeability is equal to the reservoir permeability. However, if wormhole 10 length is smaller than damaged radius then the flushed zone permeability will be less than the reservoir permeability depending on the flushed zone length.
- the stimulated matrix area is only Zone 2 . However, for organic acids (like carboxylic or aminocarboxylic acids) the stimulated matrix area will be a combination of Zone 2 and 3 because the flushed zone will have some unreacted acid.
- FIG. 2 shows the effect of increasing the permeability in the damaged zone on the skin factor.
- Original formation permeability is 100 md
- damaged radius is 1.5 ft (0.46 m)
- well bore radius is 0.5 ft (15 cm)
- damaged permeability is 5 md.
- the initial skin factor will be 20.9; as the permeability increased toward the original value, the skin factor is reduced dramatically.
- the reduction in the skin factor becomes small.
- increasing the permeability 10 times above the original value will not result in a significant reduction in the skin factor value.
- FIG. 3 is a graph showing the effect of increasing the damaged zone radius on the skin factor.
- Original formation permeability is 100 md and improved damaged formation permeability after stimulation is 1000 md. Based on these values, the initial skin factor will be ⁇ 1 when the permeability enhancement covers the original damaged zone radius. However, if acid is stimulated further deep inside the formation, the skin factor will be reduced even more ( FIG. 3 ). Based on results shown in FIGS. 2 and 3 , enhancing the permeability deeply into the formation will result in much better well production than that from created wormholes.
- STIMCARBTM-GLDA acid strength was carried out by core flood testing (dynamic fluid flow) with 10% versus 20% active material of STIMCARBTM-GLDA using carbonate cores.
- STIMCARBTM-GLDA is GLDA available from Baker Hughes Incorporated. “10 wt % STIMCARBTM-GLDA” means 10 wt % active GLDA and 90 wt % aqueous solvent.
- FIG. 4 The pictures of the limestone cores before and after injection are shown in FIG. 4 .
- the limestone cores treated with 10% STIMCARBTM-GLDA are shown at ( 1 a ), ( 1 b ), and ( 1 c ), where ( 1 a ) is a photo of the core before injection, and ( 1 b ) is a photo of the inlet of the core after injection, and ( 1 c ) is a photo of the outlet of the core after injection.
- FIG. 4 the limestone cores treated with 10% STIMCARBTM-GLDA are shown at ( 1 a ), ( 1 b ), and ( 1 c ), where ( 1 a ) is a photo of the core before injection, and ( 1 b ) is a photo of the inlet of the core after injection, and ( 1 c ) is a photo of the outlet of the core after injection.
- FIG. 4 the limestone cores treated with 10% STIMCARBTM-GLDA are shown at ( 1 a ), ( 1 b ),
- the limestone cores treated with 20% STIMCARBTM-GLDA are shown at ( 1 d ), ( 1 e ), and ( 1 f ), where ( 1 d ) is a photo of the core before injection, and ( 1 e ) is a photo of the inlet of the core after injection, and ( 1 f ) is a photo of the outlet of the core after injection.
- FIG. 5 The plot of pressure drop across the core as a function of injected pore volumes is shown in FIG. 5 .
- Pictures of the core after injection do indicate that wormholes could be created by 10% STIMCARBTM-GLDA but it takes more than twice the acid volume required for injection than with 20% STIMCARBTM-GLDA.
- the FIG. 5 data involved pressure drop across the core as a function of cumulative pore volume (PV) at an injection rate of 1 cc/min at 300° F. (149° C.), with five gpt (gallons per thousand gallons, or in SI units liters per thousand liters) of CI-111.
- CI-111 is a quaternary ammonium based corrosion inhibitor product available from Baker Hughes Incorporated.
- the effluent fluids from both cores was collected over time in both experiments and were subsequently analyzed for calcium content by inductively coupled plasma-optical emission spectrometry (ICP-OES).
- the calcium content was plotted against the cumulative pore volume as shown in FIG. 6 while in FIG. 7 the cumulative calcium content (mg) versus cumulative pore volume (PV) was plotted.
- Analysis of the total calcium content in the eluent does show that 10% STIMCARBTM-GLDA contained more calcium content (538.8 mg) than 20% STIMCARBTM-GLDA (451.2 mg).
- 10% STIMCARBTM-GLDA required a higher pore volume of the acid to react and chelate calcium carbonate compare to 20% STIMCARBTM-GLDA (see FIG. 5 ).
- the CT-scan images of the 20% STIMCARBTM-GLDA treated core demonstrated a better network of wormholes than the 10% STIMCARBTM-GLDA treated core.
- FIGS. 8 and 9 where the left side of each image is a CT scan of the entire limestone core, while the right side of each image models the wormhole created by the acid.
- the cumulative amount of calcium dissolved by the latter acid was more than the former.
- wormholes in the fracture face can increase the reactive surface area, resulting in excessive leakoff and rapid spending of the acid (that is, the etched length will be too short).
- this problem can be overcome by, for example, using viscosified acids.
- Viscosified acids can also be used in relatively high permeability formations.
- Acid can be viscosified with polymers (e.g. crosslinked or uncrosslinked polysaccharides), viscoelastic surfactants (VESs), nitrogen and foaming agents, or acid-in-oil emulsions.
- the 20% active STIMCARBTM-GLDA may be replaced with the viscosified acid (such as viscosified 10% vol/vol STIMCARBTM-GLDA).
- the acids described herein may be viscosified using any of the techniques known in the art or yet to be developed including, but not necessarily limited to, crosslinked or uncrosslinked polymers, VESs, nitrogen and foaming agents, and/or acid-in-oil emulsions.
- the flushed zone is the zone between the reservoir fluid and the wormhole zone developed by the carboxylic or aminocarboxylic acid (zone 3 in FIG. 1 ).
- Carboxylic acids or aminocarboxylic acids are retarded acids that initiate some permeability enhancement in the flushed zone. Ignoring any permeability enhancement in the flushed zone, and assuming equivalent amount of active components in both acid concentrations, both acids (10 and 20 wt % active GLDA) should give the same skin factor because they have same wormhole length. However 20 wt % GLDA will require less volume compare to 10%.
- the overall skin reduction of 10 wt % active material will be lower than 20% as shown S 2 and S 3 (skin factor calculations in Table I).
- the values of skin factor shown in Table I can be more significant when wormhole length is less than damage zone where any enhancement of the flushed zone will give a significant reduction in skin.
- K in Table I refers to the matrix permeability in the flushed zone area (zone 3 ).
- the method for acidizing a subterranean formation may include first injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume, and subsequently injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume.
- a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal
- the first step differs from the second step by a parameter.
- the different parameters may include, but not necessarily limited to, one or more of the following: (1) the first concentration is greater than the second concentration, (2) the second volume is greater than the first volume (increased volume in the flush zone enhances the permeability of the matrix), (3) the first volume is greater than the second volume, where the first concentration is less than the second concentration, (4) the second acid is at least partially neutralized by the addition of a base, and/or (5) the first acid is a carboxylic acid with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4, where the pH of the first acid and the pH of the second acid are different.
- a high BHT is defined as at least 200° F. (93° C.); alternatively above about 250° F. (about 121° C.), and in a different non-limiting embodiment greater than about 300° F. (about 149° C.).
- the high BHT may be defined as between about 250 and about 350° F. (about 121 and about 177° C.).
- An alternative lower threshold for these ranges may be 150° F. (65.5° C.).
- the first concentration ranges from about 10 independently to about 40 wt % acid (high concentration), and the second concentration ranges from about 0.01 to about 10 wt % acid (low concentration), less than the first concentration.
- a high or first concentration may range from about 20 independently to about 40 wt % acid.
- the term “independently” means that any lower threshold may be combined with any upper threshold to form a suitable, alternative range.
- a low or second concentration may range from about 0.01 independently to about 10 wt % acid.
- the second volume of acid is greater than the first volume of acid by an amount ranging from about 5 independently to about 200 times more; alternatively from about 10 independently to about 100 times more.
- the method may include injecting through the wellbore a third acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a third step, where the third acid has a third acid concentration ranging between about 0.01 independently to about 40 wt %; alternatively between about 0.01 independently to about 10 wt %.
- a third acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a third step, where the third acid has a third acid concentration ranging between about 0.01 independently to about 40 wt %; alternatively between about 0.01 independently to about 10 wt %.
- the acids used in the two or more injecting steps may be the same or different from one another. More than one of the suitable acids may be used in each injecting step.
- the first concentration ranges from about 11 independently to about 40 wt %, alternatively from about 20 independently to about 40 wt %
- the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of Groups 1 and/or 2 of the Periodic Table and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof.
- Suitable bases in this group include, but are not necessarily limited to, sodium hydroxide, calcium oxide or hydroxide, magnesium oxide or hydroxide, potassium hydroxide, and the like, and combinations thereof.
- the high bottom hole temperature is between about 250 and about 350° F. (about 121 and about 177° C.).
- the first acid has a pH adjusted by the presence of a base to be in the range of from about 4 independently to about 12; alternatively from about 4 independently to about 14.
- the pH in of the second acid or its salt is in the range of from about 1 independently to about 4; alternatively from about 1 independently to about 14.
- the pHs in the two steps are different from one another.
- the first concentration ranges from about 5 independently to about 40 wt %; alternatively from about 20 independently to about 40 wt %, where the second concentration is less than 5 wt %, or alternatively about 38 wt % or less.
- the second acid is at least partially neutralized by the addition of a base to form its salt selected from the group consisting of oxides of Groups 1, 2 and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof.
- the bottom hole temperature is between greater than about 300° F. (about 149° C.).
- Suitable organic acids include, but are not necessarily limited to, glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA); nitrilotriacetic acid (NTA); ethylene diamine tetraacetic acid (EDTA); hydroxyethyl ethylene diamine triacetic acid (HEDTA); diethylene triamine pentaacetic acid (DTPA); propylene diamine tetraacetic acid (PDTA); ethylene diamine-N,N′′-di(hydroxyphenyl acetic) acid (EDDHA); ethylene diamine-N,N′′-di(hydroxy-methylphenyl acetic) acid (EDDHMA); ethanol diglycine (EDG); trans-1,2-cyclohexylene dinitrilotetraacetic
- mineral acids may be used in conjunction with or together with the carboxylic acids and/or aminocarboxylic acids as described herein, in alternative embodiments.
- the mineral acids may include, but are not necessarily limited to, hydrochloric acids, phosphoric acid, sulfuric acid, hydrobromic acid, hydrofluoric acid, nitric acid and/or boric acid, and chemical equivalents of these acids.
- Suitable subterranean formations for the methods and compositions described herein include, but are not necessarily limited to, formations selected from the group consisting of sandstone formations, limestone formations, and combinations thereof.
- the permeability of the subterranean formation is increased compared to a method that consists of only injecting the first acid or only injecting the second acid.
- this permeability increase is quantified by an increase in production from about 5 independently to about 90 vol %; alternatively from about 10 independently to about 95 vol %.
- the present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed.
- a method for acidizing a subterranean formation where the method consists essentially of or consists of injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, dicarboxylic acids, and/or aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume; and injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, dicarboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and
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Abstract
An injection process to treat sandstone or limestone subterranean formations using carboxylic acids, dicarboxylic acids and/or aminocarboxylic acids (e.g. glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA), etc.), further involves at least a two step injection process which may include, in one non-limiting embodiment, injecting a relatively higher concentration of organic acid to create wormholes accompanied by a relatively lower concentration of the same or different organic acid to enhance the permeability of the formation.
Description
- The present invention relates to methods and compositions for enhancing the acidizing treatment of subterranean formations, and more particularly to methods and compositions for using carboxylic acids and/or aminocarboxylic acids to create wormholes.
- It is well known that the production of oil and gas is often controlled by the rate at which oil and gas can be extracted from the subterranean formations containing them. No matter how much oil and gas is present, unless the oil and gas can flow to a well bore for removal at a commercially practical rate, it has no value. One means for improving the rate at which oil and gas may be removed from a subterranean formation is the use of acidizing and fracturing treatments.
- Such treatments use aqueous acidic solutions and are commonly carried out in hydrocarbon-containing subterranean formations to accomplish a number of purposes, one of which is to increase the permeability of the formation or by-pass near well bore damage. The increase in formation permeability normally results in an increase in the recovery of hydrocarbons from the formation.
- In acidizing treatments, aqueous acidic solutions are introduced into the subterranean formation under pressure so that the acidic solution flows into the pore spaces of the formation. One common type of subterranean formation is sandstone formations, which contain siliceous materials like quartz as the major constituent and which in addition may contain various amounts of clays (aluminosilicates such as kaolinite or illite) or alkaline aluminosilicates such as feldspars, and zeolites, as well as carbonates (calcite, dolomite, ankerite) and iron-based minerals (hematite and pyrite). In sandstone there normally is an amount of calcium carbonate and one way to make sandstone more permeable is to perform a so-called acidizing step, wherein an acid solution is pumped into the formation.
- The acidic solution reacts with acid-soluble materials contained in the sandstone or limestone formation which results in an increase in the size of the pore spaces and an increase in the permeability of the formation. Similarly, in fracture-acidizing treatments, one or more fractures are produced in the formation and the acidic solution is introduced into the fracture to etch flow channels in the fracture face. The acid also enlarges the pore spaces in the fracture face and in the formation.
- The rate at which acidizing fluids react with reactive materials in the subterranean formation is a function of various factors including but not limited to acid concentration, temperature, fluid velocity and the type of reactive material encountered. Whatever the rate of reaction of the acidic solution, the solution can be introduced into the formation only a certain distance before it becomes spent. It is desirable to maintain the acidic solution in a reactive condition for as long a period of time as possible to maximize the permeability enhancement produced by the acidic solution.
- The use of acids downhole is not without problems. One such problem is that the acids, in addition to increasing the permeability of a hydrocarbon bearing formation, may also cause excessive corrosion of the downhole metal equipment. Anything made of metal in contact with the acid may be subject to such excessive corrosion.
- It would be desirable in the art to use acids that limit or minimize the corrosion of metal downhole during acid stimulation treatments of oil and gas wells, while still increasing the local permeability.
- There is provided, in one non-limiting embodiment a method for acidizing a subterranean formation, where the method involves injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume. The method further involves subsequently injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume. The steps are modified by the first step differing from the second step by at least one of the following parameters:
-
- the first concentration is greater than the second concentration;
- the second volume is greater than the first volume,
- the first volume is greater than the second volume, where the first concentration is less than the second concentration;
- the second acid is at least partially neutralized by the addition of a base;
- the first acid is a carboxylic acid or its salt with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4; and
- combinations thereof.
The bottom hole temperature of the wellbore are at least 150° F. (65.5° C.).
- The following Figures are part of the present specification, included to demonstrate certain aspects of various embodiments of this disclosure and referenced in the detailed description herein:
-
FIG. 1 is a schematic, cross-section illustration of a wellbore and stimulation zones around the wellbore after acid injection; -
FIG. 2 is a theoretical graph of skin factor as a function of damaged zone permeability illustrating the effect of increasing the permeability in the damaged zone on the skin factor, where the original formation permeability is 100 md, while the damaged permeability is 5 md; -
FIG. 3 is a theoretical graph of skin factor as a function of zone radius illustrating the effect of increasing the damaged zone radius on the skin factor, where the original formation permeability is 100 md, where the damaged permeability is originally 5 md but has been stimulated to be 1000 md; -
FIG. 4 is a series of photographs of limestone cores before and after injection of GLDA; -
FIG. 5 is a graph of pressure drop across the core as a function of cumulative pore volume at an injection rate of 1 cc/min, 300° F. (149° C.), and 5 gpt (or liters per thousand liters) of CI-111 corrosion inhibitor; -
FIG. 6 is a plot of calcium (Ca in mg) as a function of cumulative pore volume (PV) for 50% vol/vol STIMCARB™-GLDA (20 wt % active) compared to 25% vol/vol STIMCARB™-GLDA (10 wt % active); -
FIG. 7 is a plot of cumulative calcium (Ca in mg) as a function of cumulative pore volume (PV) for 50% vol/vol STIMCARB™-GLDA (20 wt % active) compared to 25% vol/vol StimCarb-GLDA (10 wt % active); -
FIG. 8 are CT-Scan images showing worm-hole distribution for a limestone core treated with 25% vol/vol STIMCARB™-GLDA; and -
FIG. 9 are CT-Scan images showing worm-hole distribution for a limestone core treated with 50% vol/vol STIMCARB™-GLDA. - It will be appreciated that
FIG. 1 is a schematic illustration which is not necessarily to scale and that certain features are exaggerated for clarity, and thus the methods and apparatus described herein should not be limited by the drawings. - Recently there has been a growing interest in utilizing glutamic acid N,N-diacetic acid (GLDA) for the treatment of limestone or sandstone formations which have high bottom hole temperatures. One of the main benefits of utilizing GLDA for matrix acidizing is lowered reactivity compared to hydrochloric acid (HCl) or some other organic acids, making it ideal for high temperature conditions. Other benefits include the incorporation of chelation chemistry, enabling it to function as an effective iron control agent (that is, the GLDA also functions as a chelant), and provide better tubular protection even at higher temperatures (is less corrosive), compared to conventional acid systems, as well as biodegradability.
- Several existing patents disclose some of the benefits of GLDA described and are mainly limited to the chemistry or composition of the fluid or field applicability of the fluid. New research work has unexpectedly led to the discovery that GLDA (and other carboxylic acids, dicarboxylic acids and amino carboxylic acids) may be used in optimized application engineering designs to maximize GLDA's stimulation efficiency and reduce overall treatment cost.
- As defined herein, “carboxylic acid” encompasses monocarboxylic acids, dicarboxylic acids and polycarboxylic acids. Further, as defined herein, “aminocarboxylic acid” encompasses aminomonocarboxylic acids, aminodicarboxylic acids and aminopolycarboxylic acids
- Carboxylic or aminocarboxylic acid are retarded acids. Recent experimental work discovered that reducing concentration or pH of dicarboxylic or aminocarboxylic acid can result in local permeability enhancement rather than the wormhole creation. Also, it has been discovered that reducing the active material concentration and injecting a larger volume of diluted dicarboxylic or aminocarboxylic acid results in a lower skin factor because of increased unreacted acid in the flushed zone; for instance, see
zone 3 inFIG. 1 . - “Skin factor” is a dimensionless numerical value used to analytically model the difference from the pressure drop predicted by Darcy's law due to skin (zone of reduced permeability immediately around a wellbore). Typical skin factor values range from −6 for an infinite conductivity massive hydraulic fracture to more than 100 for a poorly executed gravel pack.
- As used herein “skin” refers to a damaged zone, which is
zone 2 inFIG. 1 , and may includezone 3. The initial skin factor is positive forzone 2, while it is zero forzone 3. After injection of acid according to the method herein, the skin factor will be negative for both zones (zones 2 and 3). This will improve production as compared to previous techniques where only the skin factor ofzone 2 was reduced. Thus, one advantage of the method described herein is that the permeability may be increased and the skin inzone 3 is reduced, in addition to which production is increased. - The general method may be described with reference to a variety of particular embodiments, a few of which are briefly summarized as follows:
-
- 1. Injection of a high concentration of carboxylic and/or aminocarboxylic acid (e.g. from about 10 to about 40 wt %) to create wormholes (for instance,
wormholes 10 inzone 2 inFIG. 1 ), followed by injection of low active material concentration of dicarboxylic and/or aminocarboxylic acid (e.g. from about 0.01 to about 10 wt %) to improve the permeability of the flushed zone (zone 3 inFIG. 1 ). - 2. Injection of larger volume of relatively low concentration carboxylic and/or aminocarboxylic acid after the injection of relatively high concentration with less volume of the same acid to enlarge the stimulated matrix area (
zones FIG. 1 ), in one non-limiting embodiment to enlargezone 3. - 3. Injection of a relatively high concentration of carboxylic and/or aminocarboxylic acid followed by a relatively lower concentration of the same acid in wells with bottom hole temperatures greater than 200° F. (93° C.).
- 4. Alternatively, injection of a relatively high concentration of carboxylic and/or aminocarboxylic acid accompanied by a relatively lower concentration (e.g. of about 5 to about 10 wt %) of a carboxylic and/or aminocarboxylic acid with neutralized pH in wells with bottom hole in a temperature range of about 250 to about 350° F. (about 121 to about 177° C.).
- 5. In another optional embodiment, injection of a relatively high concentration of carboxylic and/or aminocarboxylic acid followed by a relatively lower concentration, e.g. <5% of dicarboxylic and/or aminocarboxylic acid with neutralized pH in wells with a bottom hole temperature of greater than about 300° F. (about 149° C.).
- 6. Injection of a carboxylic acid or its salt with a pH range of about 4 to 12 about followed by injection of a carboxylic acid with a pH range of about 1 to about 4.
- 7. Optionally, the above embodiments may also include subsequent injection of a relatively low concentration of a carboxylic and/or an aminocarboxylic acid (e.g. from about 0.01 to about 10 wt %) to enlarge the pore radius and remove any scale from the entire formation, not necessarily to create wormholes to bypass the damage zone.
- 1. Injection of a high concentration of carboxylic and/or aminocarboxylic acid (e.g. from about 10 to about 40 wt %) to create wormholes (for instance,
- Conventional hydrochloric acid (HCl) is used to stimulate subterranean carbonate formations by creating wormholes (long channels with infinite permeability) that bypass the damage near the wellbore as shown in
zone 2 ofFIG. 1 . This near wellbore damage is generally the result of drilling mud or cement-filtrate invasion. This damage can significantly affect productivity adversely, and is typically easier to prevent than to cure. Nevertheless, there is a need to cure damage that sometimes is inevitable. -
Zone 2 ofFIG. 1 schematically indicates thewormholes 10 stimulated in the zone by the HCl. However, HCl does not stimulate the rest of the formation since typically all of the HCl is consumed (spent) to create thewormholes 10. Therefore, even inzone 1, the matrix around thewormholes 10 still has damaged permeability. -
Zone 3 represents the flushed zone containing neutralized HCl utilized forwormhole 10 creation. The permeability of the flushed zone is dependent on thewormhole 10 length. If thewormhole 10 length is greater than the damaged radius then the flushed zone permeability is equal to the reservoir permeability. However, ifwormhole 10 length is smaller than damaged radius then the flushed zone permeability will be less than the reservoir permeability depending on the flushed zone length. Typically for HCl acid, the stimulated matrix area isonly Zone 2. However, for organic acids (like carboxylic or aminocarboxylic acids) the stimulated matrix area will be a combination ofZone -
FIG. 2 shows the effect of increasing the permeability in the damaged zone on the skin factor. The following values were assigned as an example: Original formation permeability is 100 md, damaged radius is 1.5 ft (0.46 m), well bore radius is 0.5 ft (15 cm), and damaged permeability is 5 md. Based on these values, the initial skin factor will be 20.9; as the permeability increased toward the original value, the skin factor is reduced dramatically. However, after damaged zone improves to the original permeability value, the reduction in the skin factor becomes small. And based on the data inFIG. 2 , increasing thepermeability 10 times above the original value will not result in a significant reduction in the skin factor value. -
FIG. 3 is a graph showing the effect of increasing the damaged zone radius on the skin factor. The following values were assigned as an example: Original formation permeability is 100 md and improved damaged formation permeability after stimulation is 1000 md. Based on these values, the initial skin factor will be −1 when the permeability enhancement covers the original damaged zone radius. However, if acid is stimulated further deep inside the formation, the skin factor will be reduced even more (FIG. 3 ). Based on results shown inFIGS. 2 and 3 , enhancing the permeability deeply into the formation will result in much better well production than that from created wormholes. - The following examples describe certain specific embodiments of the invention. Other embodiments within the scope of the claims herein will be apparent to one skilled in the art from consideration of the specification or practice of the methods as disclosed herein. It is intended that the specification, together with the examples, be considered exemplary only, with the scope and spirit of the invention being indicated by the claims which follow the examples. In the examples, all percentages are given on a weight basis unless otherwise indicated.
- Investigation into the effect of STIMCARB™-GLDA acid strength was carried out by core flood testing (dynamic fluid flow) with 10% versus 20% active material of STIMCARB™-GLDA using carbonate cores. STIMCARB™-GLDA is GLDA available from Baker Hughes Incorporated. “10 wt % STIMCARB™-GLDA” means 10 wt % active GLDA and 90 wt % aqueous solvent.
- The pictures of the limestone cores before and after injection are shown in
FIG. 4 . InFIG. 4 , the limestone cores treated with 10% STIMCARB™-GLDA are shown at (1 a), (1 b), and (1 c), where (1 a) is a photo of the core before injection, and (1 b) is a photo of the inlet of the core after injection, and (1 c) is a photo of the outlet of the core after injection. Similarly, inFIG. 4 , the limestone cores treated with 20% STIMCARB™-GLDA are shown at (1 d), (1 e), and (1 f), where (1 d) is a photo of the core before injection, and (1 e) is a photo of the inlet of the core after injection, and (1 f) is a photo of the outlet of the core after injection. - The plot of pressure drop across the core as a function of injected pore volumes is shown in
FIG. 5 . Pictures of the core after injection do indicate that wormholes could be created by 10% STIMCARB™-GLDA but it takes more than twice the acid volume required for injection than with 20% STIMCARB™-GLDA. TheFIG. 5 data involved pressure drop across the core as a function of cumulative pore volume (PV) at an injection rate of 1 cc/min at 300° F. (149° C.), with five gpt (gallons per thousand gallons, or in SI units liters per thousand liters) of CI-111. CI-111 is a quaternary ammonium based corrosion inhibitor product available from Baker Hughes Incorporated. - The effluent fluids from both cores was collected over time in both experiments and were subsequently analyzed for calcium content by inductively coupled plasma-optical emission spectrometry (ICP-OES). The calcium content was plotted against the cumulative pore volume as shown in
FIG. 6 while inFIG. 7 the cumulative calcium content (mg) versus cumulative pore volume (PV) was plotted. Analysis of the total calcium content in the eluent does show that 10% STIMCARB™-GLDA contained more calcium content (538.8 mg) than 20% STIMCARB™-GLDA (451.2 mg). However, 10% STIMCARB™-GLDA required a higher pore volume of the acid to react and chelate calcium carbonate compare to 20% STIMCARB™-GLDA (seeFIG. 5 ). On the other hand, the CT-scan images of the 20% STIMCARB™-GLDA treated core demonstrated a better network of wormholes than the 10% STIMCARB™-GLDA treated core. Please seeFIGS. 8 and 9 , where the left side of each image is a CT scan of the entire limestone core, while the right side of each image models the wormhole created by the acid. However, the cumulative amount of calcium dissolved by the latter acid was more than the former. These results confirm that 10% STIMCARB™-GLDA improves the permeability of the matrix rather than developing wormhole as the 20% STIMCARB™-GLDA does. - One of the major problems in acidizing is the creation of wormholes in the fracture face. The wormholes can increase the reactive surface area, resulting in excessive leakoff and rapid spending of the acid (that is, the etched length will be too short). To some extent, this problem can be overcome by, for example, using viscosified acids. Viscosified acids can also be used in relatively high permeability formations. Acid can be viscosified with polymers (e.g. crosslinked or uncrosslinked polysaccharides), viscoelastic surfactants (VESs), nitrogen and foaming agents, or acid-in-oil emulsions. To come back to the topic of the GLDA tests, the 20% active STIMCARB™-GLDA may be replaced with the viscosified acid (such as viscosified 10% vol/vol STIMCARB™-GLDA). In one non-limiting embodiment, the acids described herein may be viscosified using any of the techniques known in the art or yet to be developed including, but not necessarily limited to, crosslinked or uncrosslinked polymers, VESs, nitrogen and foaming agents, and/or acid-in-oil emulsions.
- The flushed zone is the zone between the reservoir fluid and the wormhole zone developed by the carboxylic or aminocarboxylic acid (
zone 3 inFIG. 1 ). Carboxylic acids or aminocarboxylic acids are retarded acids that initiate some permeability enhancement in the flushed zone. Ignoring any permeability enhancement in the flushed zone, and assuming equivalent amount of active components in both acid concentrations, both acids (10 and 20 wt % active GLDA) should give the same skin factor because they have same wormhole length. However 20 wt % GLDA will require less volume compare to 10%. - On the other hand, consider the enhancement in the flushed zone as it should be, the overall skin reduction of 10 wt % active material will be lower than 20% as shown S2 and S3 (skin factor calculations in Table I). The values of skin factor shown in Table I can be more significant when wormhole length is less than damage zone where any enhancement of the flushed zone will give a significant reduction in skin. K in Table I refers to the matrix permeability in the flushed zone area (zone 3).
-
TABLE I The Skin Factor Calculations when Considering the Enhancement in the Flushed Zone S1 (ignore S3 (10X increase Injected permeability in S2 (4X increase in in K in flushed GLDA acid, PV flushed zone) K in flushed zone) zone) 20% 2.38 −1.79 −2.12 −2.2 10% 5.90 −1.79 −2.45 −2.63 - Turning to a more detailed discussion of the various embodiments, the method for acidizing a subterranean formation may include first injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume, and subsequently injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume. Within these at least two injecting steps, the first step differs from the second step by a parameter. The different parameters may include, but not necessarily limited to, one or more of the following: (1) the first concentration is greater than the second concentration, (2) the second volume is greater than the first volume (increased volume in the flush zone enhances the permeability of the matrix), (3) the first volume is greater than the second volume, where the first concentration is less than the second concentration, (4) the second acid is at least partially neutralized by the addition of a base, and/or (5) the first acid is a carboxylic acid with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4, where the pH of the first acid and the pH of the second acid are different.
- The methods described herein are particularly applicable for improving (enhancing) acidizing treatments of formations having high bottom hole temperatures (BHTs). In one non-limiting embodiment, a high BHT is defined as at least 200° F. (93° C.); alternatively above about 250° F. (about 121° C.), and in a different non-limiting embodiment greater than about 300° F. (about 149° C.). Alternatively, the high BHT may be defined as between about 250 and about 350° F. (about 121 and about 177° C.). An alternative lower threshold for these ranges may be 150° F. (65.5° C.).
- In one non-limiting embodiment herein, there are two steps and the first concentration ranges from about 10 independently to about 40 wt % acid (high concentration), and the second concentration ranges from about 0.01 to about 10 wt % acid (low concentration), less than the first concentration. Alternatively, a high or first concentration may range from about 20 independently to about 40 wt % acid. As used herein with respect to a range, the term “independently” means that any lower threshold may be combined with any upper threshold to form a suitable, alternative range. Alternatively, a low or second concentration may range from about 0.01 independently to about 10 wt % acid.
- In another non-limiting version, in the two step method described herein, the second volume of acid is greater than the first volume of acid by an amount ranging from about 5 independently to about 200 times more; alternatively from about 10 independently to about 100 times more.
- There may be one or more subsequent acid injections besides the initial two. For instance, after the second injecting, the method may include injecting through the wellbore a third acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a third step, where the third acid has a third acid concentration ranging between about 0.01 independently to about 40 wt %; alternatively between about 0.01 independently to about 10 wt %.
- The acids used in the two or more injecting steps may be the same or different from one another. More than one of the suitable acids may be used in each injecting step.
- In a different non-limiting embodiment, the first concentration ranges from about 11 independently to about 40 wt %, alternatively from about 20 independently to about 40 wt %, and the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of
Groups 1 and/or 2 of the Periodic Table and combinations thereof, hydroxides ofGroups - In another non-limiting embodiment, the first acid has a pH adjusted by the presence of a base to be in the range of from about 4 independently to about 12; alternatively from about 4 independently to about 14. The pH in of the second acid or its salt is in the range of from about 1 independently to about 4; alternatively from about 1 independently to about 14. The pHs in the two steps are different from one another.
- In still another non-restrictive embodiment, the first concentration ranges from about 5 independently to about 40 wt %; alternatively from about 20 independently to about 40 wt %, where the second concentration is less than 5 wt %, or alternatively about 38 wt % or less. In this optional embodiment, the second acid is at least partially neutralized by the addition of a base to form its salt selected from the group consisting of oxides of
Groups Groups - While it is expected that carboxylic acids will be the acids used, dicarboxylic acids and aminocarboxylic acids are particularly suitable. Suitable organic acids include, but are not necessarily limited to, glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA); nitrilotriacetic acid (NTA); ethylene diamine tetraacetic acid (EDTA); hydroxyethyl ethylene diamine triacetic acid (HEDTA); diethylene triamine pentaacetic acid (DTPA); propylene diamine tetraacetic acid (PDTA); ethylene diamine-N,N″-di(hydroxyphenyl acetic) acid (EDDHA); ethylene diamine-N,N″-di(hydroxy-methylphenyl acetic) acid (EDDHMA); ethanol diglycine (EDG); trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA); glucoheptonic acid; gluconic acid; sodium citrate; acetic acid; formic acid; lactic acid; citric acid; malonic acid; succinic acid; adipic acid; glutaric acid; malic acid; tartaric acid; alkali metal salts of these acids; amine salts of these acids; and combinations thereof.
- It will be appreciated that mineral acids may be used in conjunction with or together with the carboxylic acids and/or aminocarboxylic acids as described herein, in alternative embodiments. The mineral acids may include, but are not necessarily limited to, hydrochloric acids, phosphoric acid, sulfuric acid, hydrobromic acid, hydrofluoric acid, nitric acid and/or boric acid, and chemical equivalents of these acids.
- Suitable subterranean formations for the methods and compositions described herein include, but are not necessarily limited to, formations selected from the group consisting of sandstone formations, limestone formations, and combinations thereof.
- It will be appreciated that in the present method the permeability of the subterranean formation is increased compared to a method that consists of only injecting the first acid or only injecting the second acid. In one non-limiting embodiment, this permeability increase is quantified by an increase in production from about 5 independently to about 90 vol %; alternatively from about 10 independently to about 95 vol %.
- It will be additionally appreciated that in the acid injecting steps herein, it will be acceptable to include common and/or conventional additives present in acidizing treatments including, but not necessarily limited to, corrosion inhibitors, surfactants, demulsifiers, solvents, scale control, iron control, clay control, bacteria control, viscosifying agents such as VES surfactants, polyacrylamides, crosslinked guar, as well as other synthetic polymers, breakers, and diverting agents.
- In the foregoing specification, the invention has been described with reference to specific embodiments thereof. It has been demonstrated as effective in providing methods and compositions for acidizing subterranean formations, particularly to improve or enhance the acidizing, such as by creating wormholes, and/or increasing the permeability of the zones near the wellbore, alone or together with also being able to use reduced concentrations and/or reduced volumes of acids, both of which would lower costs. However, it will be evident that various modifications and changes can be made thereto without departing from the broader spirit or scope of the invention as set forth in the appended claims. Accordingly, the specification is to be regarded in an illustrative rather than a restrictive sense. For example, specific combinations of carboxylic acids, dicarboxylic acids, aminocarboxylic acids, bases, and other components falling within the claimed parameters, but not specifically identified or tried in a particular composition or under specific conditions, are anticipated to be within the scope of this invention.
- As used herein, the word “comprising” as used throughout the claims is to be interpreted to mean “including but not limited to”.
- The present invention may suitably comprise, consist or consist essentially of the elements disclosed and may be practiced in the absence of an element not disclosed. For instance, there may be provided a method for acidizing a subterranean formation, where the method consists essentially of or consists of injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, dicarboxylic acids, and/or aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume; and injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, dicarboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume; where the first step differs from the second step by a parameter selected from the group consisting of: the first concentration is greater than the second concentration; the second volume is greater than the first volume; the first volume is greater than the second volume, where the first concentration is less than the second concentration; the second acid is at least partially neutralized by the addition of a base; the first acid is a carboxylic acid with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4; and combinations thereof.
Claims (17)
1. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume; and
injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume;
where:
the first step differs from the second step by a parameter selected from the group consisting of:
the first concentration is greater than the second concentration;
the first concentration is greater than the second concentration and the first volume is less than the second volume;
the first volume is greater than the second volume, where the first concentration is less than the second concentration;
the second acid is at least partially neutralized by the addition of a base;
the first acid is a carboxylic acid or its salt with a pH ranging from about 4 to about 12 and the second acid is a carboxylic acid with a pH ranging from about 1 to about 4; and
combinations thereof; and
the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).
2. The method of claim 1 where the first concentration ranges from about 10 to about 40 wt % acid, and the second concentration ranges from about 0.01 to about 10 wt % acid.
3. The method of claim 1 where the second volume of acid is greater than the first volume of acid by an amount ranging from about 5 times to about 200 times greater volume more.
4. The method of claim 1 where the first acid and the second acid are the same acid.
5. The method of claim 1 where:
the first concentration ranges from about 11 to about 40 wt %;
the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of Groups 1, 2 and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof; and
the bottom hole temperature is between about 150 and about 350° F. (about 65.5 and about 177° C.).
6. The method of claim 1 where:
the first concentration ranges from about 5 to about 40 wt %;
the second concentration is less than 5 wt %;
the second acid is at least partially neutralized by the addition of a base selected from the group consisting of oxides of Groups 1, 2 and combinations thereof, hydroxides of Groups 1, 2 and combinations thereof, and combinations thereof; and
the bottom hole temperature is between greater than about 300° F. (about 149° C.).
7. The method of claim 1 further comprising injecting through the wellbore a third acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of dicarboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a third step, where the third acid has a third concentration ranging between about 0.01 to about 10 wt %.
8. The method of claim 1 where the carboxylic acids and aminocarboxylic acids are selected from the group consisting of glutamic acid N,N-diacetic acid (GLDA); methylglycine N,N-diacetic acid (MGDA); diethylene triamine pentaacetic acid (DTPA); nitrilotriacetic acid (NTA); ethylene diamine tetraacetic acid (EDTA); hydroxyethyl ethylene diamine triacetic acid (HEDTA); diethylene triamine pentaacetic acid (DTPA); propylene diamine tetraacetic acid (PDTA); ethylene diamine-N,N″-di(hydroxyphenyl acetic) acid (EDDHA); ethylene diamine-N,N″-di(hydroxy-methylphenyl acetic) acid (EDDHMA); ethanol diglycine (EDG); trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA); glucoheptonic acid; gluconic acid; sodium citrate; acetic acid; formic acid; lactic acid; citric acid; malonic acid; succinic acid; adipic acid; glutaric acid; malic acid; tartaric acid; alkali metal salts of these acids; amine salts of these acids; and combinations thereof.
9. The method of claim 1 where the carboxylic acid is a dicarboxylic acid.
10. The method of claim 1 where the subterranean formation comprises formations selected from the group consisting of sandstone formations, limestone formations, and combinations thereof.
11. The method of claim 1 where the permeability of the subterranean formation is increased compared to a method that consists of only injecting the first acid or only injecting the second acid.
12. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration between 10 to about 40 wt % and a first volume;
followed by injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration between about 0.01 and less than 10 wt % and a second volume; and
the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).
13. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration from about 10 to about 40 wt % acid, and a first volume; and
followed by injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration from about 0.5 to about 38 wt % acid, and a second volume that is higher than the first volume of acid by an amount ranging from about 5 to about 200 times more; and
the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).
14. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration from about 10 to about 40 wt % acid, and a first volume; and
injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration from about 0.01 to about 10 wt % acid, and a second volume;
where:
the first acid and the second acid are the same acid; and
the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).
15. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration between about 11 to about 40 wt %, and a first volume; and
injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration from about 5 to about 10 wt %, and a second volume, the second acid at least partially neutralized by the addition of a base;
where:
the bottom hole temperature of the wellbore is between about 150 and about 350° F. (about 65.5 and about 177° C.).
16. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration between 5 to about 40 wt %, and a first volume; and
injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, aminocarboxylic acids, alkali metal salts and amine salts of carboxylic acids, alkali metal salts and amine salts of aminocarboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration of less than 5 wt %, and a second volume, the second acid at least partially neutralized by the addition of a base;
where:
the bottom hole temperature of the wellbore is greater than 300° F. (about 149° C.).
17. A method for acidizing a subterranean formation, the method comprising:
injecting through a wellbore in the subterranean formation a first acid selected from the group consisting of carboxylic acids, alkali metal salts and amine salts of carboxylic acids, and combinations thereof in a first step, where the first acid has a first concentration and a first volume, the first acid having a pH adjusted by the presence of a base to be in the range of from about 4 to about 12; and
injecting through the wellbore a second acid selected from the group consisting of carboxylic acids, alkali metal salts and amine salts of carboxylic acids, and combinations thereof in a second step, where the second acid has a second concentration and a second volume and a pH in the range of from about 1 to about 4;
where:
the bottom hole temperature of the wellbore is at least 150° F. (65.5° C.).
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PCT/US2015/029755 WO2015175318A1 (en) | 2014-05-15 | 2015-05-07 | Method for enhancing acidizing treatment of a formation having a high bottom hole temperature |
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US11407933B2 (en) * | 2019-10-28 | 2022-08-09 | King Fahd University Of Petroleum And Minerals | Location and orientation control by acid etching process |
WO2023141186A1 (en) * | 2022-01-21 | 2023-07-27 | Baker Hughes Oilfield Operations Llc | Modeling acid flow in a formation |
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CN111011032B (en) * | 2019-12-11 | 2021-11-26 | 中国烟草总公司郑州烟草研究院 | Method for reducing content of chloride ions in chlorine-sensitive crops |
CN111004617B (en) * | 2019-12-17 | 2021-02-19 | 中国地质大学(武汉) | Environment-friendly acidizing working fluid suitable for low-permeability carbonate reservoir and preparation method thereof |
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