Carbon dioxide-steam co-injection tertiary oil recovery process

Claim 2

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) heating feedwater to generate steam; (b) injecting a carbonate-containing pH adjusting agent into the steam to form a pH adjusting agent-containing steam; (c) injecting carbon dioxide into the pH adjusting agent-containing steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5; (d) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation; and (e) withdrawing oil from the formation.

Claim 3

The process of claim 1 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 7.

Claim 4

The process of claim 1 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.7.

Claim 5

The process of claim 1 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.4.

Claim 6

The process of claim 1 wherein step (b) includes the step of injecting a sufficient amount of the carbonate-containing pH adjusting agent into the steam for the pH adjusting agent-containing steam to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm.

Claim 7

The process of claim 1 wherein step (b) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the steam for the pH adjusting agent-containing steam to have a carbonate-containing buffering agent concentration of at least about 500 ppm, the enhanced oil recovery composition having a pH of about 6.3 to about 7.

Claim 8

The process of claim 1 wherein step (b) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the steam for the pH adjusting agent-containing steam to have a carbonate-containing buffering agent concentration of at least about 500 ppm, the enhanced oil recovery composition having a pH of about 6.3 to about 6.7.

Claim 9

The process of claim 1 wherein step (b) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the steam for the pH adjusting agent-containing steam to have a carbonate-containing buffering agent concentration of at least about 500 ppm, the enhanced oil recovery composition having a pH of about 6.3 to about 6.4.

Claim 10

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) injecting a carbonate-containing pH adjusting agent into the feedwater to form a pH adjusting agent-containing feedwater, (b) heating the pH adjusting agent-containing feedwater to generate steam having a liquid phase and a vapor phase, (c) injecting carbon dioxide into the steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5, (d) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation, and (e) withdrawing oil from the formation.

Claim 11

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) injecting a carbonate-containing pH adjusting agent into the feedwater to form a pH adjusting agent-containing feedwater, (b) heating the pH adjusting agent-containing feedwater to generate steam having a liquid phase and a vapor phase, (c) injecting carbon dioxide into the steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5, (d) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation, and (e) withdrawing oil from the formation.

Claim 12

The process of claim 9 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 7.

Claim 13

The process of claim 9 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.7.

Claim 14

The process of claim 9 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.4.

Claim 15

The process of claim 9 wherein step (a) includes the step of injecting a sufficient amount of the carbonate-containing pH adjusting agent into the feedwater for the pH adjusting agent-containing feedwater to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm.

Claim 16

The process of claim 9 wherein step (a) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the feedwater for the pH adjusting agent-containing feedwater to have a carbonate-containing buffering agent concentration of at least about 500 ppm, the enhanced oil recovery composition having a pH of about 6.3 to about 7.

Claim 17

The process of claim 9 wherein step (a) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the feedwater for the pH adjusting agent-containing feedwater to have a carbonate-containing buffering agent concentration of at least about 500 ppm, the enhanced oil recovery composition having a pH of about 6.3 to about 6.7.

Claim 18

The process of claim 9 wherein step (a) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the feedwater for the pH adjusting agent-containing feedwater to have a carbonate-containing buffering agent concentration of at least about 500 ppm, the enhanced oil recovery composition having a pH of about 6.3 to about 6.4.

Claim 19

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) heating feedwater to generate steam having a liquid phase and a vapor phase, (b) injecting carbon dioxide into the steam to form a carbon dioxide-containing steam, (c) injecting a carbonate-containing pH adjusting agent into the carbon dioxide-containing steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5, (d) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation, and (e) withdrawing oil from the formation.

Claim 20

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) heating feedwater to generate steam having a liquid phase and a vapor phase, (b) injecting carbon dioxide into the steam to form a carbon dioxide-containing steam, (c) injecting a carbonate-containing pH adjusting agent into the carbon dioxide-containing steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5, (d) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation, and (e) withdrawing oil from the formation.

Claim 21

The process of claim 17 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 7.

Claim 22

The process of claim 17 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.7.

Claim 23

The process of claim 17 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.4.

Claim 24

The process of claim 17 wherein step (c) includes the steps of injecting a sufficient amount of the carbonate-containing pH adjusting agent into the carbon dioxide-containing steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm.

Claim 25

The process of claim 17 wherein step (c) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the carbon dioxide-containing steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm and a pH about 6.3 to about 7.

Claim 26

The process of claim 17 wherein step (c) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the carbon dioxide-containing steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm and a pH about 6.3 to about 6.7.

Claim 27

The process of claim 17 wherein step (c) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the carbon dioxide-containing steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm and a pH about 6.3 to about 6.4.

Claim 28

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) heating feedwater to generate steam having a liquid phase and a vapor phase, (b) substantially simultaneously injecting (i) a carbonate-containing pH adjusting agent and (ii) carbon dioxide into the steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5. (c) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation, and (d) withdrawing oil from the formation.

Claim 29

A process for reducing corrosion of well tubing while recovering oil from an oil-bearing formation using a carbon dioxide-steam co-injection method, the process comprising the steps of: (a) heating feedwater to generate steam having a liquid phase and a vapor phase, (b) substantially simultaneously injecting (i) a carbonate-containing pH adjusting agent and (ii) carbon dioxide into the steam to form an enhanced oil recovery composition having a pH of about 6.3 to less than 7.5. (c) injecting the enhanced oil recovery composition into at least a portion of an oil-bearing formation, and (d) withdrawing oil from the formation.

Claim 30

The process of claim 25 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 7.

Claim 31

The process of claim 25 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.7.

Claim 32

The process of claim 25 wherein the enhanced oil recovery composition has a pH of about 6.3 to about 6.4.

Claim 33

The process of claim 25 wherein step (b) includes the step of injecting a sufficient amount of the carbonate-containing pH adjusting agent into the steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm.

Claim 34

The process of claim 25 wherein step (b) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm and a pH about 6.3 to about 7.

Claim 35

The process of claim 25 wherein step (b) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm and a pH about 6.3 to about 6.7.

Claim 36

The process of claim 25 wherein step (b) includes the step of injecting a sufficient amount of a carbonate-containing pH adjusting agent into the steam for the enhanced oil recovery composition to have a carbonate-containing pH adjusting agent concentration of at least about 500 ppm and a pH about 6.3 to about 6.4.