Method for using CO

1. A method for both enhancing oil recovery of a reservoir and sequestering CO 2 , the method comprising:

dissolving CO 2 in a base fluid at a surface location of an injection formation to increase the density of the base fluid and form a dense CO 2 -brine solution, wherein the base fluid is a residual brine from desalination processing, a sea water, a fresh water, synthetic brine, a produced brine, or combinations thereof, wherein:

the dense CO 2 -brine solution has a density greater than a native formation fluid of the injection formation, and

the injection formation is a same geologic formation or a different geologic formation from a hydrocarbon bearing formation, wherein the injection formation comprises a structural low and the hydrocarbon bearing formation comprises a structural high, wherein the structural low is in fluid communication with the structural high via a hydraulic connection;

introducing the dense CO 2 -brine solution into an injection well having an injection point proximate to the structural low, thereby accumulating a volume of the dense CO 2 -brine solution in the structural low;

displacing the native formation fluid from the injection well to a producing well having a receiving end proximate to the structural high via the hydraulic connection to form a displaced native formation fluid, thereby increasing a fluid drive pressure of the hydraulic connection; and

displacing hydrocarbons of the producing well with the displaced native formation fluid via the fluid drive pressure of the hydraulic connection.

2. The method of claim 1 , wherein identifying the injection formation hydraulically connected to a hydrocarbon bearing formation further comprises:

obtaining, by a computer system, seismic data regarding a geological region of interest;

deconvoluting, by a computer system, the seismic data, well-log data, production data, regarding the geologic region of interest; and

transmitting, by the computer system, the geologic region of interest comprising the injection formation hydraulically connected to a hydrocarbon-bearing formation.

3. The method of claim 1 , further comprising:

measuring a density of the native formation fluid of the injection formation

measuring CO 2 solubility in the base fluid as a function of a salinity of the base fluid, pressure, temperature, or combinations thereof.

4. The method of claim 3 , wherein the produced brine comprises an aqueous fluid selected from the group consisting of a formation water, a frac or flowback water, and combinations thereof.

5. The method of claim 1 , dissolving CO 2 in a base fluid at a surface location of the injection formation further comprises providing an injection system at the surface location of the injection system.

6. The method of claim 5 , further comprising storing CO 2 via a CO 2 storage mechanism in the base fluid.

7. The method of claim 1 , wherein the injection formation hydraulically connected to the hydrocarbon-bearing formation is a syncline or an anticline.

8. The method of claim 1 , wherein the injection formation and the hydrocarbon bearing formation is an aquifer-reservoir pair.

9. The method of claim 1 , further comprising:

deriving an optimal dense CO 2 fluid injection rate prior to introducing the dense CO 2 -brine solution into the formation.

10. The method of claim 1 , further comprising producing a formation brine via a production well from the injection formation or via a hydrocarbon production well.

11. The method of claim 9 , further comprising:

transporting the base fluid to an injection system in fluid communication with the injection well of the injection formation; and

dissolving CO 2 in the base fluid in the injection system, wherein the base fluid comprises a formation brine.

12. A system for both enhancing oil recovery of a reservoir and sequestering CO 2 , the system comprising:

an injection system in fluid communication with an injection well having an injection point proximate to a structural low in an injection formation in fluid communication with a hydrocarbon production formation via a hydraulic connection, wherein a production well is disposed with a receiving end proximate to a structural high of the hydrocarbon production formation, wherein the injection formation and the hydrocarbon production formation are a same geologic formation or different geologic formations; and

a dense CO 2 -brine solution having a density greater than a native formation fluid present in the injection formation, wherein the dense CO 2 -brine solution comprises an amount of CO 2 dissolved in a base fluid, and

wherein the base fluid is a residual brine from desalination processing, a sea water, a fresh water, a synthetic brine, a produced brine, or combinations thereof, and

wherein the dense CO 2 -brine solution is configured to accumulate in the structural low of the injection well, and

wherein the injection system is configured to inject the dense CO 2 -brine solution into the injection well.

13. The system of claim 12 , wherein the injection formation and the hydrocarbon bearing formation is an aquifer-reservoir pair.

14. The system of claim 12 , wherein the production well, an optional production line in the injection formation, or both produces a native formation fluid.

15. The system of claim 12 , wherein the produced brine is selected from the group consisting of a formation water, a frac or flowback water, and combinations thereof.

16. The system of claim 12 , wherein the dense CO 2 -brine solution further comprises one or more additives selected from the group consisting of weighting agents, viscosifiers, polymers, surfactants, and combinations thereof.

17. The system of claim 16 , wherein the one or more weighting agents are selected from the group consisting of barite, hematite, calcium carbonate, siderite, gels, fines, and combinations thereof.

18. The system of claim 12 , wherein the injection formation and the hydrocarbon production formation is an aquifer-reservoir pair.