WO2019086864A1 - A method for reducing water flow in a subterranean formation - Google Patents
A method for reducing water flow in a subterranean formation Download PDFInfo
- Publication number
- WO2019086864A1 WO2019086864A1 PCT/GB2018/053148 GB2018053148W WO2019086864A1 WO 2019086864 A1 WO2019086864 A1 WO 2019086864A1 GB 2018053148 W GB2018053148 W GB 2018053148W WO 2019086864 A1 WO2019086864 A1 WO 2019086864A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- water soluble
- formation
- water flow
- chloride
- reducing water
- Prior art date
Links
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 title claims abstract description 115
- 230000015572 biosynthetic process Effects 0.000 title claims abstract description 49
- 238000000034 method Methods 0.000 title claims abstract description 25
- 239000000945 filler Substances 0.000 claims abstract description 25
- 239000007924 injection Substances 0.000 claims abstract description 22
- 238000002347 injection Methods 0.000 claims abstract description 22
- 239000004848 polyfunctional curative Substances 0.000 claims abstract description 22
- 150000003839 salts Chemical class 0.000 claims abstract description 17
- 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 13
- HCHKCACWOHOZIP-UHFFFAOYSA-N Zinc Chemical compound [Zn] HCHKCACWOHOZIP-UHFFFAOYSA-N 0.000 claims description 12
- FYYHWMGAXLPEAU-UHFFFAOYSA-N Magnesium Chemical compound [Mg] FYYHWMGAXLPEAU-UHFFFAOYSA-N 0.000 claims description 10
- 239000000126 substance Substances 0.000 claims description 9
- 229910052725 zinc Inorganic materials 0.000 claims description 9
- 229910052749 magnesium Inorganic materials 0.000 claims description 8
- 238000005086 pumping Methods 0.000 claims description 7
- 239000000700 radioactive tracer Substances 0.000 claims description 7
- 229910052708 sodium Inorganic materials 0.000 claims description 7
- 239000011701 zinc Substances 0.000 claims description 7
- ZLMJMSJWJFRBEC-UHFFFAOYSA-N Potassium Chemical compound [K] ZLMJMSJWJFRBEC-UHFFFAOYSA-N 0.000 claims description 6
- 150000002500 ions Chemical class 0.000 claims description 6
- 239000011777 magnesium Substances 0.000 claims description 6
- 229910052700 potassium Inorganic materials 0.000 claims description 6
- 239000011734 sodium Substances 0.000 claims description 6
- 239000011591 potassium Substances 0.000 claims description 5
- 239000012857 radioactive material Substances 0.000 claims description 4
- 239000004411 aluminium Substances 0.000 claims description 3
- XAGFODPZIPBFFR-UHFFFAOYSA-N aluminium Chemical compound [Al] XAGFODPZIPBFFR-UHFFFAOYSA-N 0.000 claims description 3
- 229910052782 aluminium Inorganic materials 0.000 claims description 3
- 229910017053 inorganic salt Inorganic materials 0.000 claims description 3
- 239000000463 material Substances 0.000 claims description 3
- 238000005755 formation reaction Methods 0.000 description 39
- CDBYLPFSWZWCQE-UHFFFAOYSA-L sodium carbonate Substances [Na+].[Na+].[O-]C([O-])=O CDBYLPFSWZWCQE-UHFFFAOYSA-L 0.000 description 33
- UXVMQQNJUSDDNG-UHFFFAOYSA-L Calcium chloride Chemical compound [Cl-].[Cl-].[Ca+2] UXVMQQNJUSDDNG-UHFFFAOYSA-L 0.000 description 21
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 20
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 20
- PMZURENOXWZQFD-UHFFFAOYSA-L Sodium Sulfate Chemical compound [Na+].[Na+].[O-]S([O-])(=O)=O PMZURENOXWZQFD-UHFFFAOYSA-L 0.000 description 19
- 229910001628 calcium chloride Inorganic materials 0.000 description 18
- OSGAYBCDTDRGGQ-UHFFFAOYSA-L calcium sulfate Chemical compound [Ca+2].[O-]S([O-])(=O)=O OSGAYBCDTDRGGQ-UHFFFAOYSA-L 0.000 description 18
- 229910000029 sodium carbonate Inorganic materials 0.000 description 18
- JIAARYAFYJHUJI-UHFFFAOYSA-L zinc dichloride Chemical compound [Cl-].[Cl-].[Zn+2] JIAARYAFYJHUJI-UHFFFAOYSA-L 0.000 description 18
- 239000001110 calcium chloride Substances 0.000 description 17
- 239000000203 mixture Substances 0.000 description 17
- BWHMMNNQKKPAPP-UHFFFAOYSA-L potassium carbonate Chemical compound [K+].[K+].[O-]C([O-])=O BWHMMNNQKKPAPP-UHFFFAOYSA-L 0.000 description 16
- 239000004576 sand Substances 0.000 description 13
- HEMHJVSKTPXQMS-UHFFFAOYSA-M sodium hydroxide Inorganic materials [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 13
- TWRXJAOTZQYOKJ-UHFFFAOYSA-L Magnesium chloride Chemical compound [Mg+2].[Cl-].[Cl-] TWRXJAOTZQYOKJ-UHFFFAOYSA-L 0.000 description 12
- KWYUFKZDYYNOTN-UHFFFAOYSA-M Potassium hydroxide Chemical compound [OH-].[K+] KWYUFKZDYYNOTN-UHFFFAOYSA-M 0.000 description 12
- 230000035699 permeability Effects 0.000 description 12
- VTYYLEPIZMXCLO-UHFFFAOYSA-L Calcium carbonate Chemical compound [Ca+2].[O-]C([O-])=O VTYYLEPIZMXCLO-UHFFFAOYSA-L 0.000 description 10
- TZCXTZWJZNENPQ-UHFFFAOYSA-L barium sulfate Chemical compound [Ba+2].[O-]S([O-])(=O)=O TZCXTZWJZNENPQ-UHFFFAOYSA-L 0.000 description 10
- 239000003921 oil Substances 0.000 description 10
- 229920000642 polymer Polymers 0.000 description 10
- 239000001103 potassium chloride Substances 0.000 description 10
- 235000011164 potassium chloride Nutrition 0.000 description 10
- 239000011780 sodium chloride Substances 0.000 description 10
- 229910052938 sodium sulfate Inorganic materials 0.000 description 10
- 235000011152 sodium sulphate Nutrition 0.000 description 10
- 235000011132 calcium sulphate Nutrition 0.000 description 9
- 239000002244 precipitate Substances 0.000 description 9
- 239000011592 zinc chloride Substances 0.000 description 9
- 235000005074 zinc chloride Nutrition 0.000 description 9
- BVKZGUZCCUSVTD-UHFFFAOYSA-L Carbonate Chemical compound [O-]C([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-L 0.000 description 8
- WDIHJSXYQDMJHN-UHFFFAOYSA-L barium chloride Chemical class [Cl-].[Cl-].[Ba+2] WDIHJSXYQDMJHN-UHFFFAOYSA-L 0.000 description 8
- 229910001626 barium chloride Inorganic materials 0.000 description 8
- 239000001175 calcium sulphate Substances 0.000 description 8
- 239000000499 gel Substances 0.000 description 8
- 229910000027 potassium carbonate Inorganic materials 0.000 description 8
- 239000000243 solution Substances 0.000 description 8
- 235000019738 Limestone Nutrition 0.000 description 7
- CSNNHWWHGAXBCP-UHFFFAOYSA-L Magnesium sulfate Chemical class [Mg+2].[O-][S+2]([O-])([O-])[O-] CSNNHWWHGAXBCP-UHFFFAOYSA-L 0.000 description 7
- VSCWAEJMTAWNJL-UHFFFAOYSA-K aluminium trichloride Chemical class Cl[Al](Cl)Cl VSCWAEJMTAWNJL-UHFFFAOYSA-K 0.000 description 7
- 239000006028 limestone Substances 0.000 description 7
- 229940091250 magnesium supplement Drugs 0.000 description 7
- 235000009529 zinc sulphate Nutrition 0.000 description 7
- OYPRJOBELJOOCE-UHFFFAOYSA-N Calcium Chemical compound [Ca] OYPRJOBELJOOCE-UHFFFAOYSA-N 0.000 description 6
- KRKNYBCHXYNGOX-UHFFFAOYSA-K Citrate Chemical compound [O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O KRKNYBCHXYNGOX-UHFFFAOYSA-K 0.000 description 6
- DSAJWYNOEDNPEQ-UHFFFAOYSA-N barium atom Chemical compound [Ba] DSAJWYNOEDNPEQ-UHFFFAOYSA-N 0.000 description 6
- 239000011575 calcium Substances 0.000 description 6
- 150000004649 carbonic acid derivatives Chemical class 0.000 description 6
- 239000000706 filtrate Substances 0.000 description 6
- 229910001629 magnesium chloride Inorganic materials 0.000 description 6
- 235000019341 magnesium sulphate Nutrition 0.000 description 6
- 235000011151 potassium sulphates Nutrition 0.000 description 6
- 239000011686 zinc sulphate Substances 0.000 description 6
- 239000004971 Cross linker Substances 0.000 description 5
- 235000011128 aluminium sulphate Nutrition 0.000 description 5
- 229910052788 barium Inorganic materials 0.000 description 5
- 229910052791 calcium Inorganic materials 0.000 description 5
- 229910000019 calcium carbonate Inorganic materials 0.000 description 5
- 238000002474 experimental method Methods 0.000 description 5
- 229960003975 potassium Drugs 0.000 description 5
- 238000001556 precipitation Methods 0.000 description 5
- 229910021511 zinc hydroxide Inorganic materials 0.000 description 5
- 229940007718 zinc hydroxide Drugs 0.000 description 5
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 description 4
- 239000001164 aluminium sulphate Substances 0.000 description 4
- AYJRCSIUFZENHW-UHFFFAOYSA-L barium carbonate Chemical compound [Ba+2].[O-]C([O-])=O AYJRCSIUFZENHW-UHFFFAOYSA-L 0.000 description 4
- 239000012267 brine Substances 0.000 description 4
- 238000006243 chemical reaction Methods 0.000 description 4
- PPQREHKVAOVYBT-UHFFFAOYSA-H dialuminum;tricarbonate Chemical compound [Al+3].[Al+3].[O-]C([O-])=O.[O-]C([O-])=O.[O-]C([O-])=O PPQREHKVAOVYBT-UHFFFAOYSA-H 0.000 description 4
- BUACSMWVFUNQET-UHFFFAOYSA-H dialuminum;trisulfate;hydrate Chemical compound O.[Al+3].[Al+3].[O-]S([O-])(=O)=O.[O-]S([O-])(=O)=O.[O-]S([O-])(=O)=O BUACSMWVFUNQET-UHFFFAOYSA-H 0.000 description 4
- ZLNQQNXFFQJAID-UHFFFAOYSA-L magnesium carbonate Chemical group [Mg+2].[O-]C([O-])=O ZLNQQNXFFQJAID-UHFFFAOYSA-L 0.000 description 4
- 239000001095 magnesium carbonate Substances 0.000 description 4
- 229910000021 magnesium carbonate Inorganic materials 0.000 description 4
- 229910001862 magnesium hydroxide Inorganic materials 0.000 description 4
- 238000002156 mixing Methods 0.000 description 4
- 239000001120 potassium sulphate Substances 0.000 description 4
- 239000001509 sodium citrate Substances 0.000 description 4
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 4
- 150000003467 sulfuric acid derivatives Chemical class 0.000 description 4
- 229910021653 sulphate ion Inorganic materials 0.000 description 4
- FMRLDPWIRHBCCC-UHFFFAOYSA-L Zinc carbonate Chemical compound [Zn+2].[O-]C([O-])=O FMRLDPWIRHBCCC-UHFFFAOYSA-L 0.000 description 3
- WNROFYMDJYEPJX-UHFFFAOYSA-K aluminium hydroxide Chemical compound [OH-].[OH-].[OH-].[Al+3] WNROFYMDJYEPJX-UHFFFAOYSA-K 0.000 description 3
- 229910021502 aluminium hydroxide Inorganic materials 0.000 description 3
- FNAQSUUGMSOBHW-UHFFFAOYSA-H calcium citrate Chemical compound [Ca+2].[Ca+2].[Ca+2].[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O.[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O FNAQSUUGMSOBHW-UHFFFAOYSA-H 0.000 description 3
- 239000001354 calcium citrate Substances 0.000 description 3
- 150000001805 chlorine compounds Chemical class 0.000 description 3
- 239000010779 crude oil Substances 0.000 description 3
- 239000013078 crystal Substances 0.000 description 3
- 239000012530 fluid Substances 0.000 description 3
- 239000008398 formation water Substances 0.000 description 3
- 239000003349 gelling agent Substances 0.000 description 3
- OTYBMLCTZGSZBG-UHFFFAOYSA-L potassium sulfate Chemical compound [K+].[K+].[O-]S([O-])(=O)=O OTYBMLCTZGSZBG-UHFFFAOYSA-L 0.000 description 3
- 229910052939 potassium sulfate Inorganic materials 0.000 description 3
- 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 description 3
- 235000013337 tricalcium citrate Nutrition 0.000 description 3
- 239000011667 zinc carbonate Substances 0.000 description 3
- 235000004416 zinc carbonate Nutrition 0.000 description 3
- 229910000010 zinc carbonate Inorganic materials 0.000 description 3
- UGZADUVQMDAIAO-UHFFFAOYSA-L zinc hydroxide Chemical compound [OH-].[OH-].[Zn+2] UGZADUVQMDAIAO-UHFFFAOYSA-L 0.000 description 3
- IJGRMHOSHXDMSA-UHFFFAOYSA-N Atomic nitrogen Chemical compound N#N IJGRMHOSHXDMSA-UHFFFAOYSA-N 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 description 2
- 239000002253 acid Substances 0.000 description 2
- 229940024545 aluminum hydroxide Drugs 0.000 description 2
- 230000004888 barrier function Effects 0.000 description 2
- 150000001768 cations Chemical class 0.000 description 2
- 238000005553 drilling Methods 0.000 description 2
- 238000005516 engineering process Methods 0.000 description 2
- 239000013505 freshwater Substances 0.000 description 2
- VTHJTEIRLNZDEV-UHFFFAOYSA-L magnesium dihydroxide Chemical compound [OH-].[OH-].[Mg+2] VTHJTEIRLNZDEV-UHFFFAOYSA-L 0.000 description 2
- 239000000347 magnesium hydroxide Substances 0.000 description 2
- 238000004519 manufacturing process Methods 0.000 description 2
- 239000011148 porous material Substances 0.000 description 2
- 239000001508 potassium citrate Substances 0.000 description 2
- 229960002635 potassium citrate Drugs 0.000 description 2
- QEEAPRPFLLJWCF-UHFFFAOYSA-K potassium citrate (anhydrous) Chemical compound [K+].[K+].[K+].[O-]C(=O)CC(O)(CC([O-])=O)C([O-])=O QEEAPRPFLLJWCF-UHFFFAOYSA-K 0.000 description 2
- 235000011082 potassium citrates Nutrition 0.000 description 2
- 231100000331 toxic Toxicity 0.000 description 2
- 230000002588 toxic effect Effects 0.000 description 2
- NWONKYPBYAMBJT-UHFFFAOYSA-L zinc sulfate Chemical compound [Zn+2].[O-]S([O-])(=O)=O NWONKYPBYAMBJT-UHFFFAOYSA-L 0.000 description 2
- BVKZGUZCCUSVTD-UHFFFAOYSA-M Bicarbonate Chemical compound OC([O-])=O BVKZGUZCCUSVTD-UHFFFAOYSA-M 0.000 description 1
- BPQQTUXANYXVAA-UHFFFAOYSA-N Orthosilicate Chemical compound [O-][Si]([O-])([O-])[O-] BPQQTUXANYXVAA-UHFFFAOYSA-N 0.000 description 1
- AYJRCSIUFZENHW-DEQYMQKBSA-L barium(2+);oxomethanediolate Chemical compound [Ba+2].[O-][14C]([O-])=O AYJRCSIUFZENHW-DEQYMQKBSA-L 0.000 description 1
- 230000000903 blocking effect Effects 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 150000001875 compounds Chemical class 0.000 description 1
- 238000002425 crystallisation Methods 0.000 description 1
- 230000003247 decreasing effect Effects 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 238000005206 flow analysis Methods 0.000 description 1
- 238000009472 formulation Methods 0.000 description 1
- 150000004679 hydroxides Chemical class 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 229910052943 magnesium sulfate Inorganic materials 0.000 description 1
- 238000012544 monitoring process Methods 0.000 description 1
- 229910052757 nitrogen Inorganic materials 0.000 description 1
- 239000004033 plastic Substances 0.000 description 1
- 229920003023 plastic Polymers 0.000 description 1
- 230000001376 precipitating effect Effects 0.000 description 1
- 229940083542 sodium Drugs 0.000 description 1
- 235000015424 sodium Nutrition 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 238000010998 test method Methods 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
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
- C09K8/5045—Compositions based on water or polar solvents containing inorganic compounds
-
- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/50—Compositions for plastering borehole walls, i.e. compositions for temporary consolidation of borehole walls
- C09K8/504—Compositions based on water or polar solvents
-
- 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
- E21B33/00—Sealing or packing boreholes or wells
- E21B33/10—Sealing or packing boreholes or wells in the borehole
- E21B33/13—Methods or devices for cementing, for plugging holes, crevices or the like
- E21B33/138—Plastering the borehole wall; Injecting into the formation
Definitions
- the present invention relates to a method to divert, inhibit and prevent the addition of water to oil produced from subterranean formations.
- the polymers and cross linkers used in these methods have a high hazard rating classification as many of them are toxic and flammable.
- the present invention is directed to a method for reducing water flow in a subterranean formation comprising the steps of: selecting a suitable point of injection; injecting a hardener into the formation; and injecting a filler into the formation from another point of entry; wherein the above steps result in the formation of one or more insoluble salts.
- the hardener comprises a water soluble inorganic salt and water.
- the inorganic salt is selected from a group comprising calcium, barium, zinc, magnesium and aluminium chlorides.
- the hardener has a concentration between 5% to 35%.
- the step of selecting a suitable point of injection can be performed by repeating the injection of a hardener into the formation from different points of injection.
- the step of selecting a suitable point of injection can also be performed by injecting a tracer which can be detected and analysed by online detectors or analysers.
- the tracer can be a radioactive material or a chemical material.
- the filler comprises one or more soluble carbonate or sulphate.
- the filler may additionally comprises soluble hydroxides.
- the filler further comprises at least one monovalent ion selected from sodium or potassium and/or at least one divalent ion selected from magnesium, zinc, or aluminium.
- the present invention is a pumping and placement scheme, where the Hardener (Chlorides solutions) is pumped into a water injector well, where it will enter the subterranean formation and travel through the water bearing formation till it exits through oil producer well.
- the filler Carbonate or Sulphate solutions
- the chemical composition uses more than one Cation like Ca +2 , Ba +2 , Mg +2 , Zn +2 , and Al +2 as Chlorides to precipitate their relevant Carbonates.
- the highest density of these carbonates is Barium Carbonate, and the lowest density is Magnesium Carbonate.
- the use of Sodium or Potassium Hydroxide with the Filler (Sodium and Potassium Carbonate) precipitates Gelatinous Zinc, Magnesium and Aluminium Hydroxide.
- the present invention is a method to divert, inhibit and prevent the inclusion of water with oil produced from subterranean formation.
- a solution of Calcium chloride brine is injected in a water injector well.
- the Calcium Chloride brine is of concentration between 5% to 35% depending of the formation permeability, injectivity, and Calcium Chloride brine viscosity.
- the Calcium Chloride solution is defined as a hardener.
- the process could and may be repeated from different point of injection to select the best point of injection.
- the process of selecting a suitable point of injection could be a further injection of the hardener solution or injection of a radioactive material known as a tracer, or a chemical tracer.
- the monitoring of the tracer, whether it is chemical or radioactive material would include the installation of online detector and analysers.
- a solution of water soluble salts such as Sodium, Potassium, Calcium, Barium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate and Hydrogen Carbonate, is injected from a point of interest which is an oil producer well from which crude oil is produced with subterranean water.
- the water soluble salts are defined as a filler.
- the water soluble salts of the filler will then react with the previously injected Calcium Chloride brine (hardener) to form insoluble salt of Sodium, or Potassium, Calcium, Barium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate Sulphateor a mixture of the mentioned insoluble salts.
- the precipitation of insoluble salts will happen only in areas where injection water flow through the subterranean formation. Further injection or pumping of the water soluble salts would result in further deposition of the insoluble salts in and around the flow path of subterranean water to create a barrier between the crude oil and the formation water. This barrier will divert, inhibit and restrict the injection water from being produced with oil. Thus allowing less water and more oil to flow through the oil bearing subterranean formation.
- the principle of the present invention is to provide a simple and effective method of reducing water flow by creating insoluble precipitates in the zone of interest. These precipitates cannot travel through a permeable formation like fluids. The precipitates will lodge and accumulate in and around the pore throat of the formation which will result in blockage and diversion.
- the present invention further provides a method which is more stable.
- the precipitated Sodium, or Potassium, Calcium, Barium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate does not disintegrate with time like polymers. On the contrary, they tend to harden and become more like cement.
- the present invention does not involve pumping any gel or cross linkable mixture into the treated zone.
- the fluid pumped into the formation from oil producing well is soluble salt (Filler) which does not have any potential reaction with the crude oil but has the potential to react with the formation water which is the subject of the problem.
- the present invention also can be prepared by many types of mixing equipment or through recirculation of mixing water.
- the present invention does not incorporate any flammable chemicals.
- the hazard classification of the chemicals involved are very low and they are part of the daily drilling chemicals used in drilling, production and workover. None of the fillers and hardeners are toxic and some of them are used in food industry (Sodium carbonate, sodium and potassium citrate).
- Apparatus Permeability plugging apparatus, Nitrogen cylinder or Hydraulic pump.
- the principle of the experiment is to soak a column of sand and calcium carbonate (formation) in a solution of Calcium, Barium and Zinc Chloride and then pass a solution of Sodium or potassium carbonate, or sulphate or citrate individually and then jointly as a mixture through the soaked formation.
- a precipitate of Calcium Sulphate, Barium Sulphate, Zinc Carbonate, Zinc Hydroxide and/or Calcium Citrate will form and lodge in the permeability of the formation blocking the pass for the any flow.
- the success of the experiment will depend on many factors like, formation permeability, concentration of Calcium chloride and concentration of sodium or potassium sulphate, carbonate and citrate.
- the success criteria is the partial blockage of the flow path to complete blockage of flow path which is represented by filtrate collection from bottom valve under pressure.
- a mixture of sand 20-40 mesh and calcium carbonate 40-200 mesh (formation) was dry blended and then poured into a permeability plugging apparatus to fill a height of 15 cm.
- the cell was filled with fresh water, then pressurized to 200 psi and heated to 95°C for 6 hrs. After 6 hours pressurized air was passed through the cell in order to filter out the water.
- the cell was cooled down and depressurized. 200 ml of fresh water was poured into the cell and the cell was then closed and pressurized. Pressure was applied and bottom valve was opened to collect filtrate. 10 ml were collected and valve was then closed. The cell was depressurized and top plug opened. Extra water in the cell was discarded. The cell was closed again and pressurized. Bottom valve was opened to collect the filtrate until no more water exited the cell. 35 ml was collected which represents the pore volume of the formation.
- the cell was opened and 200 ml of Calcium chloride solution 30% w/w (Hardener) was poured into the cell. The cell was then closed, pressurized to 100 psi and reheated to 95°C. The calcium chloride solution was passed through until 50 ml was filtered out, and then bottom valve was closed. The cell was left for 4 hours and then another 50 ml was passed through the bottom valve. The cell was left for overnight heated and pressurized.
- the cell was then cooled and depressurized. The bottom valve was kept closed and the top plug was opened. The excess calcium chloride solution was discarded and 200 ml of 20% Sodium Carbonate (Filler) was poured into the cell.
- the cell was closed, pressurized and heated to 95°C. Initial pressure of 100 psi was applied to the cell and bottom valve was opened to collect filtrate. Once filtrate started to flow, the bottom valve was closed. The cell was left until the temperature stabilized at 95°C. The cell was left for a soak time between 5-7 days to allow for crystal growth. After the soak time, the bottom valve was opened at the minimum flow rate. Filtrate started to flow from the bottom valve while decreasing over time until there was no flow from bottom valve.
- Permeability is the main controlling factor in the experiment. The higher the permeability the longer the time needed for soak with Filler and the more likely to achieve complete blockage or diversion in the field due to the length of the path the formation water takes which is in kilometres rather than centimetres as in the Laboratory.
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- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Chemical & Material Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Organic Chemistry (AREA)
- Materials Engineering (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- Inorganic Chemistry (AREA)
- Compounds Of Alkaline-Earth Elements, Aluminum Or Rare-Earth Metals (AREA)
- Soil Conditioners And Soil-Stabilizing Materials (AREA)
Abstract
A method for reducing water flow in a subterranean formation comprising the steps of: selecting a suitable point of injection; injecting a hardener into the formation; and injecting a filler into the formation from another point of entry; wherein the above steps result in the formation of one or more insoluble salts.
Description
The present invention relates to a method to divert, inhibit and prevent the addition of water to oil produced from subterranean formations.
The use of precipitation reactions to induce damage to water bearing formations in oilfields was proposed in the 1940s. It did not receive the same welcome of the later polymer technology described below. US2229177 describes brief trials for precipitating Calcium Sulphate in order to block and divert the flow of water in subterranean formations. The use of Calcium sulphate was combined with different types of viscosifiers and gelling agents. The effect of such viscosifiers and gelling agents on the crystallisation and crystal growth of Calcium Sulphate is not disclosed.
In the late 1990s, the same technology was revisited in RU2186940C2 and RU2139410C1 exploring the use of precipitated Calcium Sulphate combined with CMHC, and other viscosifiers to create stable viscous solids that act like mud cake deep in subterranean formations.
The discovery of plastics, polymers and cross linkers shifted the attention of scientists from these failing trials to new promising easy to harden polymers. From the early 1930s, polymers and their use in making hard gels became state of the art. These proposals were more successful above ground than underground. The exposure to high temperature, salinity, and radical changes of pH contributed to the failure of any hardened gel to last more than 6 months.
These methods to control the water flow in subterranean formations involved pumping a cross linkable mixture into subterranean formations to seal a borehole or the like which can result in complete blockage of oil production due to gel formation in the treated zone. Such compounds comprising a polymer and cross linker or Silicate and crosslinker are proposed in US-4004639, US-8053397, US-4399866, US-2229177 and US-9518208.
These previously proposed methods are also expensive due to the fact they require special mixing equipment to mix the polymer as well as the considerable cost of the polymer and cross linker.
The polymers and cross linkers used in these methods have a high hazard rating classification as many of them are toxic and flammable.
These proposed methods involve pumping all fluids and chemicals whether polymers or viscosified Calcium Chloride and Sodium Sulphate in alternate stages into the producer well.
It is an aim of the present invention to address these disadvantages.
Accordingly the present invention is directed to a method for reducing water flow in a subterranean formation comprising the steps of: selecting a suitable point of injection; injecting a hardener into the formation; and injecting a filler into the formation from another point of entry; wherein the above steps result in the formation of one or more insoluble salts.
In a preferred embodiment, the hardener comprises a water soluble inorganic salt and water. Preferably the inorganic salt is selected from a group comprising calcium, barium, zinc, magnesium and aluminium chlorides.
Preferably, the hardener has a concentration between 5% to 35%.
Advantageously, the step of selecting a suitable point of injection can be performed by repeating the injection of a hardener into the formation from different points of injection.
Alternatively, the step of selecting a suitable point of injection can also be performed by injecting a tracer which can be detected and analysed by online detectors or analysers.
Preferably, the tracer can be a radioactive material or a chemical material.
In a preferred embodiment, the filler comprises one or more soluble carbonate or sulphate.
Advantageous, the filler may additionally comprises soluble hydroxides.
Preferably, the filler further comprises at least one monovalent ion selected from sodium or potassium and/or at least one divalent ion selected from magnesium, zinc, or aluminium.
Advantageously, further injection of the water soluble salts may be necessary.
Alternatively, further pumping of the water soluble salts may be necessary.
The present invention is a pumping and placement scheme, where the Hardener (Chlorides solutions) is pumped into a water injector well, where it will enter the subterranean formation and travel through the water bearing formation till it exits through oil producer well. The filler (Carbonate or Sulphate solutions) shall be pumped and injected into the oil producer well where it will make contact with the Hardener and cause massive precipitation of Carbonates or sulphates or a mixture of them together.
In the present invention, the chemical composition uses more than one Cation like Ca+2, Ba+2, Mg+2, Zn+2, and Al+2 as Chlorides to precipitate their relevant Carbonates. The highest density of these carbonates is Barium Carbonate, and the lowest density is Magnesium Carbonate. The use of Sodium or Potassium Hydroxide with the Filler (Sodium and Potassium Carbonate) precipitates Gelatinous Zinc, Magnesium and Aluminium Hydroxide.
The utilization of mixture of high density and low density Carbonates as well as Magnesium, Zinc, and Aluminium Hydroxides in the same mixture create a gelatinous dense insoluble precipitates that hardens under subterranean formation conditions such as high temperature, pressure, salinity and pH.
The absence of viscosifiers and gelling agents is a main factor in the success of the treatment. This precipitation of carbonate create an acid soluble precipitates that can be removed by a simple treatment with Hydrochloric acid.
The use of more than one Cation like Ca+2, Ba+2, Mg+2, Zn+2, and Al+2 as Chlorides to precipitate their relevant Sulphates and Carbonates. The highest density of these Sulphates and carbonates is Barium Sulphate, and the lowest density is Magnesium Carbonate. The use of Sodium or Potassium Hydroxide with the Filler (Sodium and Potassium Carbonate or Sulphate) precipitates Gelatinous Zinc, Magnesium and Aluminium Hydroxide.
This mixture of high and low densities, acid soluble and insoluble precipitates has not been previously proposed.
The utilization of Calcium, and Barium Chlorides as Hardeners to react with water soluble Aluminium, Zinc, and Magnesium Sulphates. Unlike all prior art which focused on the Sodium Carbonate and Sodium Sulphate. The present application describes other water soluble sulphates that can provide cost effective formulation due to the use of divalent ions as well as the monovalent ions. In this reaction, the precipitated Barium and Calcium Sulphates are of high density that does not require gelatinous form to prevent them from migrating through the formation permeability. What is needed in this case is a long shut in period to allow for crystal growth and hardening.
The present invention is a method to divert, inhibit and prevent the inclusion of water with oil produced from subterranean formation. A solution of Calcium chloride brine is injected in a water injector well. The Calcium Chloride brine is of concentration between 5% to 35% depending of the formation permeability, injectivity, and Calcium Chloride brine viscosity. The Calcium Chloride solution is defined as a hardener. Depending on flow analysis and reservoir study, the process could and may be repeated from different point of injection to select the best point of injection. The process of selecting a suitable point of injection could be a further injection of the hardener solution or injection of a radioactive material known as a tracer, or a chemical tracer. The monitoring of the tracer, whether it is chemical or radioactive material would include the installation of online detector and analysers. Once a good point of injection is selected, a solution of water soluble salts such as Sodium, Potassium, Calcium, Barium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate and Hydrogen Carbonate, is injected from a point of interest which is an oil producer well from which crude oil is produced with subterranean water. The water soluble salts are defined as a filler. By coming into or making contact with the hardener, the water soluble salts of the filler will then react with the previously injected Calcium Chloride brine (hardener) to form insoluble salt of Sodium, or Potassium, Calcium, Barium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate Sulphateor a mixture of the mentioned insoluble salts. The precipitation of insoluble salts will happen only in areas where injection water flow through the subterranean formation. Further injection or pumping of the water soluble salts would result in further deposition of the insoluble salts in and around the flow path of subterranean water to create a barrier between the crude oil and the formation water. This barrier will divert, inhibit and restrict the injection water from being produced with oil. Thus allowing less water and more oil to flow through the oil bearing subterranean formation.
The principle of the present invention is to provide a simple and effective method of reducing water flow by creating insoluble precipitates in the zone of interest. These precipitates cannot travel through a permeable formation like fluids. The precipitates will lodge and accumulate in and around the pore throat of the formation which will result in blockage and diversion.
The present invention further provides a method which is more stable. The precipitated Sodium, or Potassium, Calcium, Barium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate does not disintegrate with time like polymers. On the contrary, they tend to harden and become more like cement.
Unlike previously proposed methods, the present invention does not involve pumping any gel or cross linkable mixture into the treated zone. The fluid pumped into the formation from oil producing well is soluble salt (Filler) which does not have any potential reaction with the crude oil but has the potential to react with the formation water which is the subject of the problem.
The present invention also can be prepared by many types of mixing equipment or through recirculation of mixing water.
The present invention does not incorporate any flammable chemicals. The hazard classification of the chemicals involved (Hardener and Filler) are very low and they are part of the daily drilling chemicals used in drilling, production and workover. None of the fillers and hardeners are toxic and some of them are used in food industry (Sodium carbonate, sodium and potassium citrate).
Experiments according to the present invention will now be discussed hereinbelow.
The principle of the invention is based on the following precipitation reactions:
Sodium sulphate + Calcium Chloride ➜ Sodium chloride + Calcium sulphate
water soluble water soluble water soluble insoluble ppt
Potassium sulphate + Calcium Chloride ➜ Potassium chloride + Calcium sulphate
water soluble water soluble water soluble insoluble ppt
Sodium Carbonate + Calcium Chloride ➜ Sodium chloride + Calcium carbonate
water soluble water soluble water soluble insoluble ppt
Potassium Carbonate + Calcium Chloride ➜ Potassium chloride + Calcium Carbonate
water soluble water soluble water soluble insoluble ppt
Sodium Citrate + Calcium Chloride ➜ Sodium chloride + Calcium Citrate
water soluble water soluble water soluble insoluble ppt
Potassium Citrate + Calcium Chloride ➜ Potassium chloride + Calcium Citrate
water soluble water soluble water soluble insoluble ppt
Sodium sulphate + Barium Chloride ➜ Sodium chloride + Barium sulphate
water soluble water soluble water soluble insoluble ppt
Potassium sulphate + Barium Chloride ➜ Potassium chloride + Barium sulphate
water soluble water soluble water soluble insoluble ppt
Sodium Carbonate + Barium Chloride ➜ Sodium chloride + Barium carbonate
water soluble water soluble water soluble insoluble ppt
Potassium Carbonate + Barium Chloride ➜ Potassium chloride + Barium Carbonate
water soluble water soluble water soluble insoluble ppt
Sodium Carbonate + Zinc Chloride ➜Sodium chloride + Zinc carbonate
water soluble water soluble water soluble insoluble ppt
Potassium Carbonate + Zinc Chloride ➜ Potassium chloride + Zinc Carbonate
water soluble water soluble water soluble insoluble ppt
Sodium Carbonate + Magnesium Chloride ➜ Sodium chloride + Magnesium carbonate
water soluble water soluble water soluble insoluble ppt
Potassium Carbonate + Magnesium Chloride ➜ Potassium chloride + Magnesium Carbonate
water soluble water soluble water soluble insoluble ppt
Sodium Hydroxide + Zinc Chloride ➜ Sodium chloride + Zinc Hydroxide
water soluble water soluble water soluble insoluble gel
Potassium Hydroxide + Zinc Chloride ➜ Potassium chloride + Zinc Hydroxide
water soluble water soluble water soluble insoluble gel
Sodium Hydroxide + Magnesium Chloride ➜ Sodium chloride + Magnesium Hydroxide
water soluble water soluble water soluble insoluble gel
Potassium Hydroxide + Magnesium Chloride ➜ Potassium chloride + Magnesium Hydroxide
water soluble water soluble water soluble insoluble gel
Sodium Carbonate + Aluminium Chloride ➜ Sodium chloride + Aluminium carbonate
water soluble water soluble water soluble insoluble ppt
Potassium Carbonate + Aluminium Chloride ➜ Potassium chloride + Aluminium Carbonate
water soluble water soluble water soluble insoluble ppt
Calcium Chloride + Magnesium Sulphate ➜ Magnesium chloride + Calcium Sulphate
water soluble water soluble water soluble insoluble ppt
Calcium Chloride + Zinc Sulphate ➜ Zinc chloride + Calcium Sulphate
water soluble water soluble water soluble insoluble ppt
Barium Chloride + Zinc Sulphate ➜ Zinc chloride + Barium Sulphate
water soluble water soluble water soluble insoluble ppt
Apparatus: Permeability plugging apparatus, Nitrogen cylinder or Hydraulic pump.
Materials
(Synthetic formation) Sand 20-40 mesh, 100 mesh, Calcium carbonate 40-200 mesh.
(Hardener) Calcium chloride, Barium Chloride, Zinc Chloride, Magnesium chloride and Aluminium Chloride 94%.
(Filler) Sodium, or Potassium, Magnesium, Zinc, or Aluminium Sulphate, Citrate, or Carbonate.
The principle of the experiment is to soak a column of sand and calcium carbonate (formation) in a solution of Calcium, Barium and Zinc Chloride and then pass a solution of Sodium or potassium carbonate, or sulphate or citrate individually and then jointly as a mixture through the soaked formation.
A precipitate of Calcium Sulphate, Barium Sulphate, Zinc Carbonate, Zinc Hydroxide and/or Calcium Citrate will form and lodge in the permeability of the formation blocking the pass for the any flow. The success of the experiment will depend on many factors like, formation permeability, concentration of Calcium chloride and concentration of sodium or potassium sulphate, carbonate and citrate.
The success criteria is the partial blockage of the flow path to complete blockage of flow path which is represented by filtrate collection from bottom valve under pressure.
Test Procedures
A mixture of sand 20-40 mesh and calcium carbonate 40-200 mesh (formation) was dry blended and then poured into a permeability plugging apparatus to fill a height of 15 cm. the cell was filled with fresh water, then pressurized to 200 psi and heated to 95°C for 6 hrs. After 6 hours pressurized air was passed through the cell in order to filter out the water.
The cell was cooled down and depressurized. 200 ml of fresh water was poured into the cell and the cell was then closed and pressurized. Pressure was applied and bottom valve was opened to collect filtrate. 10 ml were collected and valve was then closed. The cell was depressurized and top plug opened. Extra water in the cell was discarded. The cell was closed again and pressurized. Bottom valve was opened to collect the filtrate until no more water exited the cell. 35 ml was collected which represents the pore volume of the formation.
The cell was opened and 200 ml of Calcium chloride solution 30% w/w (Hardener) was poured into the cell. The cell was then closed, pressurized to 100 psi and reheated to 95°C. The calcium chloride solution was passed through until 50 ml was filtered out, and then bottom valve was closed. The cell was left for 4 hours and then another 50 ml was passed through the bottom valve. The cell was left for overnight heated and pressurized.
After the overnight soak, the cell was then cooled and depressurized. The bottom valve was kept closed and the top plug was opened. The excess calcium chloride solution was discarded and 200 ml of 20% Sodium Carbonate (Filler) was poured into the cell.
The cell was closed, pressurized and heated to 95°C. Initial pressure of 100 psi was applied to the cell and bottom valve was opened to collect filtrate. Once filtrate started to flow, the bottom valve was closed. The cell was left until the temperature stabilized at 95°C. The cell was left for a soak time between 5-7 days to allow for crystal growth. After the soak time, the bottom valve was opened at the minimum flow rate. Filtrate started to flow from the bottom valve while decreasing over time until there was no flow from bottom valve.
Pressure increased to 150 psi, and 200 psi with no further flow from bottom valve. The cell was cooled down, depressurized and opened from top plug. Around 120 ml of sodium carbonate solution (Filler) was left inside.
The experiment was repeated with varying formation fill to represent different degrees of permeabilities and different types of the aforementioned (Filler).
Results
| Formation composition | Calcium Chloride % | Filler type | Filler % | Results |
| Sand 20-40 mesh | 30 | Sodium Sulphate | 20 | Partial blockage |
| Sand 20-40 mesh | 30 | Sodium Carbonate | 20 | Complete blockage |
| Sand 20-40 mesh | 30 | Sodium Citrate | 20 | Partial blockage |
| Sand 20-40 mesh | 30 | Sodium Carbonate | 10 | Partial blockage |
| Limestone 40-200 | 30 | Sodium Sulphate | 20 | Complete blockage |
| Limestone 40-200 | 30 | Sodium Carbonate | 20 | Complete blockage |
| Limestone 40-200 | 30 | Sodium Citrate | 20 | Partial blockage |
| Limestone 40-200 | 30 | Mix 1:1:1 | 20 | Complete blockage |
| Limestone 40-200 | 30 | Sodium Sulphate | 10 | Complete blockage |
| Limestone 40-200 | 30 | Sodium Carbonate | 10 | Complete blockage |
| Limestone-Sand | 30 | Sodium Sulphate | 20 | Complete blockage |
| Limestone-Sand | 30 | Sodium Carbonate | 20 | Complete blockage |
As can be seen from Table 1 a partial flow to no flow was achieved in different formation composition. In high permeability formations where the sand 20-40 mesh was used alone, partial plugging was achieved.
| Formation composition | Hardener | Filler type | Results |
| Sand 20-40 mesh | Barium Chloride 20% Calcium Chloride 20% Zinc Chloride 35% |
Sodium Carbonate 20% Sodium Sulphate 20% Sodium Hydroxide 5% |
Complete blockage |
| Limestone 40-200 mesh | Complete blockage | ||
| Limestone-Sand | Complete blockage |
As can be seen from Table 2 a complete plugging was achieved in different formation composition. In high permeability formations where the sand 20-40 mesh was used alone, partial plugging was achieved.
Changing or mixing different types of Filler did not change the results greatly. Changing the composition of the Hardener changed the results in high permeability formation.
Permeability is the main controlling factor in the experiment. The higher the permeability the longer the time needed for soak with Filler and the more likely to achieve complete blockage or diversion in the field due to the length of the path the formation water takes which is in kilometres rather than centimetres as in the Laboratory.
Claims (10)
- A method for reducing water flow in a subterranean formation comprising the steps of: selecting a suitable point of injection; injecting a hardener into the formation; and injecting a filler into the formation from another point of entry; wherein the above steps result in the formation of one or more insoluble salts.
- A method for reducing water flow according to claim 1, wherein the hardener comprises a water soluble inorganic salt and water.
- A method for reducing water flow according to claim 1 or claim 2, wherein the hardener has a concentration between 5% to 35%.
- A method for reducing water flow according to any preceding claim, wherein the step of selecting a suitable point of injection can be performed by repeating the injection of a hardener into the formation from different points of injection.
- A method for reducing water flow according to any preceding claim, wherein the step of selecting a suitable point of injection can also be performed by injecting a tracer which can be detected and analysed by online detectors or analysers.
- A method for reducing water flow according to claim 5 wherein the tracer can be a radioactive material or a chemical material.
- A method for reducing water flow according to any preceding claim, wherein the filler comprises soluble salts.
- A method for reducing water flow according to any preceding claim, wherein the filler further comprises at least one monovalent ion selected from sodium or potassium and/or at least one divalent ion selected from magnesium, zinc, or aluminium.
- A method for reducing water flow according to any preceding claim, wherein further injection of the water soluble salts may be necessary.
- A method for reducing water flow according to any preceding claim, wherein further pumping of the water soluble salts may be necessary.
Applications Claiming Priority (4)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| GBGB1717929.2A GB201717929D0 (en) | 2017-10-31 | 2017-10-31 | A method of retarding the flow of water in a subterranean formation using non polymer compounds |
| GB1717929.2 | 2017-10-31 | ||
| GB1800769.0 | 2018-01-17 | ||
| GB1800769.0A GB2570637A (en) | 2017-10-31 | 2018-01-17 | A method for reducing water flow in a subterranean formation |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| WO2019086864A1 true WO2019086864A1 (en) | 2019-05-09 |
Family
ID=60580314
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| PCT/GB2018/053148 WO2019086864A1 (en) | 2017-10-31 | 2018-10-31 | A method for reducing water flow in a subterranean formation |
Country Status (2)
| Country | Link |
|---|---|
| GB (2) | GB201717929D0 (en) |
| WO (1) | WO2019086864A1 (en) |
Cited By (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2021198700A1 (en) * | 2020-04-01 | 2021-10-07 | Heriot-Watt University | Method of artificially reducing porosity |
| CN116925716A (en) * | 2023-07-26 | 2023-10-24 | 中国石油化工股份有限公司 | High-temperature-resistant high-salt inorganic precipitation plugging agent and preparation method thereof |
Citations (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| RU2139410C1 (en) * | 1998-05-18 | 1999-10-10 | Уренгойское производственное объединение им.С.А.Оруджева "Уренгойгазпром" | Method for isolation of absorption zone in wells |
| RU2186940C2 (en) * | 2000-09-13 | 2002-08-10 | Закрытое акционерное общество "Технология-99" | Method of isolation of formation water-encroached parts |
| RU2224875C2 (en) * | 2002-04-11 | 2004-02-27 | Закрытое акционерное общество "Тюменский институт нефти и газа" | Method of limiting water influx into extracting wells |
| CN105625981A (en) * | 2015-07-29 | 2016-06-01 | 中国石油化工股份有限公司 | Composite profile control method for middle-high permeability oil reservoirs |
Family Cites Families (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| US2229177A (en) * | 1939-05-26 | 1941-01-21 | Gulf Research Development Co | Water shutoff in oil and gas wells |
-
2017
- 2017-10-31 GB GBGB1717929.2A patent/GB201717929D0/en not_active Ceased
-
2018
- 2018-01-17 GB GB1800769.0A patent/GB2570637A/en not_active Withdrawn
- 2018-10-31 WO PCT/GB2018/053148 patent/WO2019086864A1/en active Application Filing
Patent Citations (4)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| RU2139410C1 (en) * | 1998-05-18 | 1999-10-10 | Уренгойское производственное объединение им.С.А.Оруджева "Уренгойгазпром" | Method for isolation of absorption zone in wells |
| RU2186940C2 (en) * | 2000-09-13 | 2002-08-10 | Закрытое акционерное общество "Технология-99" | Method of isolation of formation water-encroached parts |
| RU2224875C2 (en) * | 2002-04-11 | 2004-02-27 | Закрытое акционерное общество "Тюменский институт нефти и газа" | Method of limiting water influx into extracting wells |
| CN105625981A (en) * | 2015-07-29 | 2016-06-01 | 中国石油化工股份有限公司 | Composite profile control method for middle-high permeability oil reservoirs |
Cited By (3)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| WO2021198700A1 (en) * | 2020-04-01 | 2021-10-07 | Heriot-Watt University | Method of artificially reducing porosity |
| US12098323B2 (en) | 2020-04-01 | 2024-09-24 | Heriot-Watt University | Method of artificially reducing porosity |
| CN116925716A (en) * | 2023-07-26 | 2023-10-24 | 中国石油化工股份有限公司 | High-temperature-resistant high-salt inorganic precipitation plugging agent and preparation method thereof |
Also Published As
| Publication number | Publication date |
|---|---|
| GB201717929D0 (en) | 2017-12-13 |
| GB201800769D0 (en) | 2018-02-28 |
| GB2570637A (en) | 2019-08-07 |
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