Method for terminating or reducing water flow in a subterranean formation
View Patent ↗A method of conditioning well bores and 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 and establishes post treatment gas and oil permeability. Novel polymers and/or resins for use as a water barrier are typified by phenolformaldehyde 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.
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 phenolformaldehyde containing 1-2 weight % of at least one of sodium bisulphite, sodium metabisulphite and mixtures thereof additionally containing 10 weight % anhydrous sodium sulphate.
2. 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.
3. 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.
4. A method as claimed in claim 2 , injecting an effective amount of concentrated hydrofloric acid or hydrochloric acid sequentially with N 2 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.
5. 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 N 2 gas at STP, and the hydrochloric acid is flushed with one cube of water followed by N 2 or CO 2 gas.
6. 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.
7. A method as claimed in claim 4 , in which the concentrated hydrofloric acid is injected in the amount of 1-10 m 3 at a rate of 200 L/min. followed by 25 m 3 of N 2 gas at STP, and the hydrofloric acid flushed with 1 m 3 of water followed by 1 m 3 of N 2 gas.
8. 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.
9. A method as claimed in claim 8 , in which the hydrochloric acid is injected in an amount of 1 to 10 10 m 3 , at a rate of 200 L/min. followed by 2 m 3 of water and followed by 25 m 3 of N 2 gas at STP.
10. A method as claimed in claim 8 , injecting an effective amount of concentrated hydrofloric or hydrochloric acid sequentially with N 2 gas to restore permeability prior to injection of the aqueous polymer if the pressure differentiation is above 5 MPa, and water flushing the acid.
11. A method as claimed in claim 8 , in which the phenolformaldehyde contains 1-2 weight % of a mixture consisting essentially of 45% sodium bisulphite, 45% sodium metabisulphite and 10% anhydrous sodium sulphate.
12. A method as claimed in claim 1 , in which the phenolformaldehyde contains 1-2 weight % of a mixture consisting essentially of 45% sodium bisulphite, 45% sodium metabisulphite and 10% anhydrous sodium sulphate.
13. A method for placing an aqueous polymer comprising phenolformaldehyde 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 N 2 or CO 2 gas into the formation in a first gas injection in an amount sufficient to displace the water or flushing the water to surface with N 2 or CO 2 in an amount sufficient to displace the water, injecting the aqueous polymer into the production zone at said established injection rate, injecting N 2 or CO 2 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.
14. A method as claimed in claim 13 , additionally ascertaining the N 2 or CO 2 first gas injection rate while injecting gas into the formation to displace the water, monitoring the N 2 or CO 2 second gas injection rate, comparing the N 2 or CO 2 gas first injection rate with the N 2 or CO 2 second injection rate, and increasing the N 2 or CO 2 gas second injection rate to match the N 2 or CO 2 first injection rate to re-establish and optimize the gas permeability in the production zone.
15. A method as claimed in claim 14 , in which the aqueous polymer is injected as aqueous oil-in-polymer emulsion.
16. A method as claimed in claim 15 , in which the aqueous polymer is emulsified with up to 50 wt % oil.
17. A method as claimed in claim 14 , injecting an effective amount of concentrated hydrofloric or hydrochloric acid sequentially with N 2 gas to restore permeability prior to injection of the aqueous polymer if the pressure differentiation is above 5 MPa, and water flushing the acid.
18. A method as claimed in claimed 17 , in which 1 to 10 m 3 of hydrofloric acid is injected at a rate of 200 L/min. followed by 1 m 3 of water and followed by 25 m 3 of N 2 gas at STP.
19. A method as claimed in claim 14 , in which the aqueous polymer is injected as aqueous oil-in-polymer emulsion.
20. A method as claimed in claim 13 , 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.