Composition and method for hydraulic fracturing and evaluation and diagnostics of hydraulic fractures using infused porous ceramic proppant

Patent metadata

Field	Value
Publication number	US-12037545-B2
Application number	US-202217706688-A
Country	US
Kind code	B2
Filing date	Mar 29, 2022
Priority date	Mar 15, 2013
Publication date	Jul 16, 2024
Grant date	Jul 16, 2024

Abstract

A composition and method for hydraulically fracturing an oil or gas well to improve the production rates and ultimate recovery using a porous ceramic proppant infused with a chemical treatment agent is provided. The chemical treatment agent may be a tracer material that provides diagnostic information about the production performance of a hydraulic fracture stimulation by the use of distinguishable both water soluble and hydrocarbon soluble tracers. The tracer can be a biological marker, such as DNA. The porous ceramic proppant can be coated with a polymer which provides for controlled release of the chemical treatment agent into a fracture or well bore area over a period of time.

First claim

What is claimed is:

1. A method of diagnostic evaluation of a hydraulic fracturing of a subterranean formation, comprising:
injecting a hydraulic fluid into a stage of the subterranean formation at a rate and pressure sufficient to open a fracture therein, the fracture comprising a formation fluid and the hydraulic fluid comprising a composition comprising porous ceramic particulates having a biological marker that is stable at a temperature of about 269° F. to about 292° F., is encapsulated with a polylactic acid polymer coating, and is disposed within pores of the porous ceramic particulates; and
recovering and identifying the biological marker from the formation fluid, wherein the recovered and identified biological marker is substantially free of the porous ceramic particulates.

2. The method of claim 1 , wherein the biological marker is deoxyribonucleic acid (DNA).

3. The method of claim 2 , wherein the recovered and identified DNA is substantially free of the polylactic acid polymer coating.

4. The method of claim 2 , wherein the porous ceramic particulates further comprise a polymeric coating disposed on an outer surface of the porous ceramic particulates.

5. The method of claim 1 , wherein the porous ceramic particulates have an internal interconnected porosity of about 15% to about 35%.

6. The method of claim 2 , wherein the DNA is a synthetic DNA.

7. The method of claim 2 , wherein the DNA has a base pair sequence of GCAT and a corresponding base pair sequence of CGTA.

8. The method of claim 2 , wherein the DNA has a base pair sequence of GCGC and a corresponding base pair sequence of CGCG.

9. The method of claim 2 , wherein the DNA has a base pair sequence of ATCG and a corresponding base pair sequence of TAGC.

10. The method of claim 2 , wherein the DNA has a base pair sequence of ATCG and a corresponding base pair sequence of TAGC.

11. The method of claim 2 , wherein the DNA has a G-clamp modification.

12. The method of claim 2 , wherein the DNA has a 2-aminoadenine-T complex.

13. The method of claim 4 , wherein the polymeric coating disposed on the outer surface of the porous ceramic particulates is selected from the group consisting of an acrylate polymer, a methacrylate polymer, a styrene polymer, and combination(s) thereof.

14. The method of claim 4 , wherein the polymeric coating disposed on the outer surface of the porous ceramic particulates is selected from the group consisting of polylactic-polyglycolic acid, polyglycolics, polylactides, polylactic acid, and combination(s) thereof.

15. The method of claim 1 , wherein recovering and identifying the biological marker comprises estimating a relative hydrocarbon volume or water volume contribution based on an amount of the recovered from the formation fluid.

16. The method of claim 1 , further comprising:
injecting a second hydraulic fluid into a second stage of the subterranean formation at a rate and pressure sufficient to open a second fracture therein, the second fracture comprising a second formation fluid and the second hydraulic fluid comprising a second composition comprising additional porous ceramic particulates having a second biological marker disposed within pores of the additional porous ceramic particulates; and
recovering and identifying the second biological marker from the second formation fluid, wherein the recovered and identified second biological marker is free of the additional porous ceramic particulates.

17. The method of claim 16 , wherein the second biological marker is a second deoxyribonucleic acid (DNA) different than the first deoxyribonucleic acid.

18. The method of claim 17 , wherein the second DNA is encapsulated with a second polymeric coating, wherein the recovered and identified second DNA is substantially free of the second polymeric coating.

19. A method of diagnostic evaluation of a cased borehole, comprising:
injecting a hydraulic fluid into the cased borehole, the hydraulic fluid comprising a composition comprising porous ceramic particulates having a biological marker encapsulated with a polylactic acid polymer coating and disposed within pores of the porous ceramic particulates; and
recovering and identifying the biological marker from the cased borehole, wherein the recovered and identified biological marker is substantially free of the porous ceramic particulates.

Assignees

• Carbo Ceramics Inc

Inventors

• Duenckel Robert
• Conner Mark
• Cannan Chad
• Cady Daniel
• Leasure Joshua
• Lieng Thu
• Roper Todd
• Read Peter A

Classifications

• E21B47/11

  using tracers; using radioactivity · CPC title

• C09K2208/10

  Nanoparticle-containing well treatment fluids · CPC title

• C09K8/66

  Compositions based on water or polar solvents (C09K8/64 takes precedence) · CPC title

• E21B43/26

  by forming crevices or fractures · CPC title

• E21B43/267

  reinforcing fractures by propping · CPC title