# US 2009/0260813 A1 · Method for Terminating or Reducing Water Flow in a Subterranean Formation > Agents: this data is available as JSON from the patentgrep API and MCP server — see https://patentgrep.com/llms.txt - Number: US 2009/0260813 A1 - Document ID: US20090260813A1 - Status: Published application - Kind: A1 - Application number: 12/087,058 - Filed: 2008-01-08 - Published: 2009-10-22 - Earliest claimed: 2007-01-09 - Assignees: Renelco Energy Inc. - Inventors: Gregory E. Anderson; William J. Heaven - Web page: https://patentgrep.com/patent/US20090260813A1 ## CPC - E21B 43/32: Preventing gas- or water-coning phenomena, i.e. the formation of a conical column of gas or water around wells - C09K 8/508: macromolecular compounds {(C09K8/512 takes precedence)} - C09K 8/516: characterised by their form or by the form of their components, e.g. encapsulated material - E21B 33/138: Plastering the borehole wall; Injecting into the formation - E21B: EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS - C09K: MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE ## Abstract This invention relates to a method of reducing the deleterious effects of water production in a subterranean formation by placing an aqueous phase polymer and/or resin, which at a designated set up time, solidifies and blocks water conduits. This invention pertains specifically to a method of conditioning well bores and placing the polymer and displacing the polymer and/or resin to establish post treatment gas and oil permeability. Novel polymers and/or resins for use as a water barrier are disclosed, typified by phenoformaldehyde containing 1-2 weight % of at least one of sodium bisulphite, sodium metabisulphite or mixtures thereof. The method includes selecting a well having sizable hydrocarbon reserves with a production history of decrease of oil or gas production with concurrent increase of water production. ## Claims ### Claim 1 a method for placing an aqueous polymer in the water conduits of the: production zone of a gas or oil reservoir to form a barrier to shut off or reduce unwanted production of water, through a well-bore tubing and/or annulus of a well in communication with the production zone of the gas or oil reservoir, comprising: injecting water into the production zone to establish an injection rate into the production zone of at least 200 L/min., and injecting the aqueous polymer into the production zone at said injection rate, said aqueous polymer comprising phenoformaldehyde containing 1-2 weight % of at least one of sodium bisulphite, sodium metabisulphite and mixtures thereof additionally containing 10 weight % anhydrous sodium sulphate. ### Claim 2 (depends on 1) A method as claimed in claim 1, in which the aqueous polymer is injected at a pressure differential in the range of 2 to 5 MPa above ambient pressure of the production zone. ### Claim 3 (depends on 2) A method as claimed in claim 2, in which aqueous polymer is emulsified with up to 50 weight % oil as an aqueous oil-in-polymer emulsion. ### Claim 4 (depends on 2) A method as claimed in claim 2, injecting an effective amount of concentrated hydrofloric acid or hydrochloric acid sequentially with N2 gas to restore permeability prior to injection of the aqueous polymer if the pressure differentiation is above 5 MPa, and water flushing the hydrofloric acid or hydrochloric acid. ### Claim 5 (depends on 4) A method as claimed in claim 4, in which the concentrated hydrochloric acid is injected in an amount of 1-10 cubes at a rate of 200 L/min. with 25 cubes of N2 gas at STP, and the hydrochloric acid is flushed with one cube of water followed by N2 or CO2 gas. ### Claim 6 (depends on 4) A method as claimed in claim 4, in which the concentrated hydrofloric acid is injected in the amount of 1-10 m3 at a rate of 200 L/min. followed by 25 m3 of N2 gas at STP, and the hydrofloric acid flushed with 1 m3 of water followed by 1 m3 of N2 gas. ### Claim 7 A method for placing an aqueous polymer comprising phenoformaldehyde containing 1-2 weight % of a mixture consisting essentially of sodium bisulphite, sodium metabisulphite and mixtures thereof additionally containing 10 weight % anhydrous sodium sulphate, in the water conduits of the production zone of a gas or oil reservoir to form a barrier to shut off or reduce unwanted production of water, through a well-bore tubing and/or annulus of a well in communication with the production zone of the gas or oil reservoir, comprising: injecting water into the production zone to establish an injection rate into the production zone of at least 200 L/min. at a pressure differential in the range of 2 to 5 MPa above ambient formation pressure, injecting N2 or CO2 gas into the formation in a first gas injection in an amount sufficient to displace the water or flushing the water to surface with N2 or CO2 in an amount sufficient to displace the water, injecting the aqueous polymer into the production zone at said established injection rate, injecting N2 or CO2 to displace the aqueous polymer from the well bore into formation, to establish communication to the gas zone and to optimize gas permeability in the production zone. ### Claim 8 (depends on 7) A method as claimed in claim 7, additionally ascertaining the N2 or CO2 first gas injection rate while injecting gas into the formation to displace the water, monitoring the N2 or CO2 second gas injection rate, comparing the N2 or CO2 gas first injection rate with the N2 or CO2 second injection rate, and increasing the N2 or CO2 gas second injection rate to match the N2 or CO2 first injection rate to re-establish and optimize the gas permeability in the production zone. ### Claim 9 (depends on 8) A method as claimed in claim 8, in which the aqueous polymer is injected as aqueous oil-in-polymer emulsion. ### Claim 10 (depends on 9) A method as claimed in claim 9, in which the aqueous polymer is emulsified with up to 50 wt % oil. ### Claim 11 (depends on 6) A method as claimed in claim 6, additionally comprising pre-selecting a well which has a sizable gas or oil reservoir and in which oil or gas production has decreased concomitant with an increase in water production. ### Claim 12 (depends on 8) A method as claimed in claim 8, injecting an effective amount of concentrated hydrofloric or hydrochloric acid sequentially with N2 gas to restore permeability prior to injection of the aqueous polymer if the pressure differentiation is above 5 MPa, and water flushing the acid. ### Claim 13 A method as claimed in claimed 12, in which 1 to 10 m3 of hydrofloric acid is injected at a rate of 200 L/min. followed by 1 m3 of water and followed by 25 m3 of N2 gas at STP. ### Claim 14 (depends on 11) A method as claimed in claim 11, in which the hydrochloric acid is injected in an amount of 1 to 10 10 m3, at a rate of 200 L/min. followed by 2 m3 of water and followed by 25 m3 of N2 gas at STP. ### Claim 15 (depends on 1) A method as claimed in claim 1, in which the phenoformaldehyde contains 1-2 weight % of a mixture consisting essentially of 45% sodium bisulphite, 45% sodium metabisulphite and 10% anhydrous sodium sulphate. ### Claim 16 (depends on 5) A method as claimed in claim 5, in which aqueous polymer is emulsified with up to 50 weight % oil as an aqueous oil-in-polymer emulsion. ### Claim 17 (depends on 8) A method as claimed in claim 8, in which the aqueous polymer is injected as aqueous oil-in-polymer emulsion. ### Claim 18 (depends on 7) A method as claimed in claim 7, additionally comprising pre-selecting a well which has a sizable gas or oil reservoir and in which oil or gas production has decreased concomitant with an increase in water production. ### Claim 19 (depends on 11) A method as claimed in claim 11, injecting an effective amount of concentrated hydrofloric or hydrochloric acid sequentially with N2 gas to restore permeability prior to injection of the aqueous polymer if the pressure differentiation is above 5 MPa, and water flushing the acid. ### Claim 20 (depends on 11) A method as claimed in claim 11, in which the phenoformaldehyde contains 1-2 weight % of a mixture consisting essentially of 45% sodium bisulphite, 45% sodium metabisulphite and 10% anhydrous sodium sulphate.