# US 7,464,754 B1 · CO2 foamed well treatments

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- Number: US 7,464,754 B1
- Document ID: US7464754B1
- Status: Granted
- Kind: B1
- Application number: 11/175,956
- Filed: 2005-07-07
- Granted: 2008-12-16
- Earliest claimed: 2004-10-11
- Assignees: Team CO2, Inc.
- Inventors: Randal L. Decker; Michael D. Hyman; John J. Ridge
- Web page: https://patentgrep.com/patent/US7464754B1

## CPC

- E21B 43/164: {Injecting CO2 or carbonated water (in combination with organic material C09K8/594)}
- C09K 8/74: combined with additives added for specific purposes
- C09K 8/94: Foams
- Y10S 507/933: Acidizing or formation destroying
- Y10S 507/939: Corrosion inhibitor
- 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
- Y10S: TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS

## Abstract

A composition and a method for treating a subterranean formation with an injection liquid containing liquid carbon dioxide, a treating liquid and optionally a foaming agent and/or methanol. The treating liquid may be an acid, a corrosion inhibitor, a solvent or a scale inhibitor.

## Claims

### Claim 1

A method for treating a subterranean formation penetrated from an earth surface by at least one well, the method consisting essentially of:
a) blending a treating liquid and liquid carbon dioxide to produce an injection liquid containing from about 51 to about 95 weight percent liquid carbon dioxide and from about 5 to about 49 weight percent treating liquid;
b) injecting the injection liquid into the subterranean formation through the at least one well at a pressure below fracturing pressure in an amount sufficient to treat a desired pore volume of the formation around the at least one well; and,
c) shutting in the well for at least one hour.

### Claim 2 (depends on 1)

The method of claim 1 wherein the carbon dioxide liquid in the injection liquid is present in an amount from about 60 to about 80 weight percent.

### Claim 3 (depends on 1)

The method of claim 1 wherein the treating liquid is selected from aqueous organic or inorganic acids, aqueous corrosion inhibitors and aqueous scale inhibitors or organic solvents.

### Claim 4 (depends on 3)

The method of claim 3 wherein the treating fluid is an aqueous acid selected from the group consisting of hydrochloric, perchloric, nitric, sulfuric, phosphoric, hydrobromic, hydrofluoric, hydriodic, citric, acetic and combinations thereof.

### Claim 5 (depends on 3)

The method of claim 3 wherein the treating liquid is an aqueous organic or inorganic acid and the treating liquid contains from about 5 to about 25 weight percent methanol.

### Claim 6 (depends on 3)

The method of claim 3 wherein the treating fluid contains a foaming agent.

### Claim 7 (depends on 3)

The method of claim 3 wherein a quantity of a slug containing from about 0 to about 100 weight percent liquid carbon dioxide and from about 0 to about 100 weight percent water or crude oil is injected after the injection of the injection liquid.

### Claim 8 (depends on 1)

The method of claim 1 wherein the treating liquid contains a corrosion inhibitor or an organic solvent.

### Claim 9 (depends on 1)

The method of claim 1 wherein the treating liquid contains a scale inhibitor.

### Claim 10 (depends on 1)

The method of claim 1 wherein the well is shut in for a time from about one hour to about 24 hours after injection of the injection liquid.

### Claim 11 (depends on 1)

The method of claim 1 wherein the injection fluid is injected until a worm hole is created into a second well.