Composition and method for recovering hydrocarbon fluids from a subterranean reservoir

• US 7,897,546 B2
• Filed: 04/17/2009
• Issued: 03/01/2011
• Est. Priority Date: 04/21/2008
• Status: Active Grant

• Current Assignee: ChampionX LLC (ChampionX Corporation)
• Original Assignee: Nalco Company (Ecolab, Inc.)
• Inventors: Showalter, Brett M., Reed, Peter E., Ramesh, Manian, Street, Joseph Paul, Kurian, Pious, Chang, Kin-Tai
• Primary Examiner(s): Kugel; Timothy J.
• Application Number:
  US12/425,900
• Publication Number:
  US 20090264321A1
• Time in Patent Office: 683 Days
• Field of Search: 507/219, 507/211, 166/305.1
• US Class Current: 507/219
• CPC Class Codes: C09K 8/512 containing cross-linking agents
• CPC Class Codes: C09K 8/516 characterised by their form or by the form of their components, e.g. encapsulated material
• CPC Class Codes: C09K 8/588 characterised by the use of specific polymers polymeric surfactants C09K8/584

Abstract

This invention is directed to a composition comprising encapsulated expandable polymeric microparticles including expandable base microparticles encapsulated in a shell of at least one layer of a labile or degradable encapsulation material. The encapsulated microparticles have an unexpanded volume average particle size diameter of from about 0.05 to about 5,000 microns. The invention is further directed to the use of the composition for modifying the permeability of subterranean formations and increasing the mobilization and/or recovery rate of hydrocarbon fluids present in the formations.

Claims

1. An encapsulated polymeric microparticle composition comprising:

a) expandable polymeric microparticles; and

,

b) a shell encapsulating the expandable polymeric microparticles, the shell comprising at least one layer of a labile or degradable encapsulation material wherein the expandable polymeric microparticles have an unexpanded volume average particle size diameter of from about 0.05 to about 5,000 microns.

2. The composition of claim 1 wherein the shell is degradable upon exposure to an activating event.

3. The composition of claim 2 wherein the activating event is a change in at least one of the conditions selected from the group consisting of:

temperature, pressure, pH, salinity, shear force, and dilution.

4. The composition of claim 3 wherein the activating event comprises exposure to an activation agent.

5. The composition of claim 4 wherein the activation agent is selected from the group consisting of:

a reducing agent, an oxidation agent, an acid, a base, a biological agent, a cross-linking agent, and a salt.

6. The composition of claim 1 wherein the expandable polymeric microparticles comprise cross-linked expandable polymeric microparticles.

7. The composition of claim 6 wherein the cross-linked expandable polymeric microparticles comprise a cross linking agent content of from about 100 to about 200,000 ppm of labile cross linkers and from 0 to about 300 ppm of non-labile cross linkers.

8. The composition of claim 1 wherein the shell comprises an encapsulation material selected from the group consisting of:

cross-linked polymers, emulsifiers, thermally responsive polymers, silicone elastomers, siloxanes, starches, gum guar, derivated cellulose sulfonated polysaccharides, silica, colloidal clays, a salt, and combinations thereof.

9. The composition of claim 1 wherein shell comprises a dissolving material.

10. A method of modifying the permeability to water of a subterranean formation, comprising injecting into the subterranean formation an encapsulated polymeric microparticle composition according to claim 1 wherein the encapsulated microparticles have a smaller diameter than the pores of the subterranean formation and wherein the shell degrades under a change in environmental conditions in the subterranean formation so that the expandable polymeric microparticles are free to expand.

11. The method of claim 10 wherein the composition is added to injection water as part of a secondary or tertiary process for the recovery of hydrocarbon from the subterranean formation.

12. The method of claim 11 wherein the injection water is added to the subterranean formation at a temperature lower than the temperature of the subterranean formation.

13. The method of claim 10 wherein said change in the environmental conditions in the subterranean formation causes the encapsulation material to degrade.

14. The method of claim 13 wherein the change in the environmental conditions comprises a change in temperature, a change in pressure, a change in pH a change in salinity, a change in shear force or a change in dilution.

15. The method of claim 13 wherein introducing the change in the environmental conditions comprises introducing an activation agent into the formation.

16. The method of claim 15 wherein the activation agent comprises a reducing agent, an oxidation agent, an acid, a base or a biological agent.

17. The method of claim 10, wherein the composition is added to injection water as part of a secondary or tertiary process for the recovery of hydrocarbon fluids from the subterranean formation.

18. The method of claim 10, wherein the composition is injected into the subterranean formation as part of a carbon dioxide and water tertiary recovery project.

19. The method of claim 10, wherein the composition is injected into the subterranean formation as part of a tertiary oil recovery process, one component of which constitutes water injection.

20. The method of claim 10, wherein the subterranean formation is a sandstone or carbonate hydrocarbon reservoir.