Method of using surface modifying metallic treatment agents to treat subterranean formations

Patent metadata

Field	Value
Publication number	US-9683431-B2
Application number	US-201414491905-A
Country	US
Kind code	B2
Filing date	Sep 19, 2014
Priority date	Sep 20, 2013
Publication date	Jun 20, 2017
Grant date	Jun 20, 2017

Abstract

A method of treating a subterranean formation comprises pumping into a well penetrating the formation a surface modifying treatment agent having a metallic anchor and at least one hydrophobic tail attached to the metal of the anchor. The surface modifying treatment agent is covalently bound to the surface of the subterranean formation through the metal of the anchor.

First claim

What is claimed is:

1. A method of treating a siliceous or metal (M) oxide-containing subterranean formation penetrated by a well comprising:
a) pumping into the formation a surface modifying treatment agent having a metallic anchor and a hydrophobic tail; and
b) binding the metal of the metallic anchor of the surface modifying treatment agent to the surface of the siliceous formation or the metal, M, of the metal (M) oxide-containing subterranean formation.

2. The method of claim 1 , wherein the hydrophobic tail of the surface modifying treatment agent comprises a hydrophobic organo-silicon material, a fluorinated hydrocarbon or both a hydrophobic organo-silicon material and a fluorinated hydrocarbon and further wherein the metal is linked to the hydrophobic tail.

3. The method of claim 2 , wherein the hydrophobic organo-silicon material is a silane, polysiloxane or a polysilazane.

4. The method of 2 , wherein the metal of the surface modifying treatment agent is a Group 3, 4, 5, or 6 metal.

5. The method of claim 4 , wherein the metal of the surface modifying treatment agent is selected from the group consisting of Ti, Zr, La, Hf, Ta, W and Nb.

6. The method of claim 2 , wherein the hydrophobic organo-silicon material has a formula selected from:
R 1 4-x SiA x and (R 1 3 Si) y B
or an organo(poly)siloxane or organo(poly)silazane of the formula:

where:
R 1 are identical or different and are a hydrocarbon or substituted hydrocarbon radical containing from 1 to 100 carbon atoms;
A is hydrogen, halogen, OH, OR 2 or

B is NR 3 3-y ;
R 2 is a hydrocarbon or substituted hydrocarbon radical containing from 1 to 12 carbon atoms;
R 3 is hydrogen or R 1 ;
x is 1, 2 or 3; and

y is 1 or 2.

7. The method of claim 6 , wherein the fluorinated hydrocarbon is of the structure:

where Y is F or C n F 2n+1 ; m is 4 to 20 and n is 1 to 6; R 2 is alkyl containing from 1 to 4 carbon atoms and p is 0 to 18.

8. The method of claim 6 , wherein the fluoro-substituted hydrocarbon is of the structure:

where A is an oxygen radical or a chemical bond; n is 1 to 6, y is F or C n F 2n ; b is at least 1; m is 0 to 6 and p is 0 to 18.

9. The method of claim 2 , wherein the hydrophobic organo-silicon material is of the formula
R 1 4-x SiA x

wherein R 1 is a fluoro-substituted hydrocarbon and A is OR 2 .

10. The method of claim 9 , wherein R 1 is of the structure:

where Y is F or C n F 2n+1 ; m is 4 to 20 and n is 1 to 6; R 2 is alkyl containing from 1 to 4 carbon atoms and p is 0 to 18.

11. The method of claim 2 , wherein the hydrophobic organo-silicon material is an organo(poly)siloxane or an organo(poly)silazane.

12. The method of claim 11 , wherein the organo(poly)siloxane or an organo(poly)silazane have units of the formula:

where R 1 are identical or different and are a hydrocarbon or substituted hydrocarbon radical containing from about 1 to about 12 carbon atoms; and R 3 is hydrogen or R 1 .

13. The method of claim 12 , wherein the hydrophobic organo-silicon material contains additional units of the formula: R 5 2 SiO 2 where R 5 is halogen.

14. The method of claim 11 , wherein the organo(poly)siloxane and organo(poly)silazane has a number average molecular weight of at least 400.

15. The method of claim 14 , wherein the organo(poly)siloxane and organo(poly)silazane has a number average molecular weight between from about 1000 to about 5,000,000.

16. The method of claim 2 , wherein at least one of the following conditions prevail:
(a) the surface modifying treatment agent alters the surface energy of the formation;
(b) the surface modifying treatment agent stabilizes fines in the subterranean formation;
(c) the well is a producing well and the surface modifying treatment agent decreases the amount of formation solids flowed back from the surface of the subterranean formation into the producing well;
(d) the surface modifying treatment agent is a passive anti-microbial agent and minimizes or prevents the retention of water on the surface of the subterranean formation;
(e) the surface modifying treatment agent passively inhibits or controls scale deposition onto or within the subterranean formation;
(f) the surface modifying treatment agent passively prevents or controls deposition of organic particulates onto or within the surface of the subterranean formation;
(g) the surface modifying treatment agent decreases the swelling of clay within the subterranean formation;
(h) the surface modifying treatment increases the relative permeability of the formation to oil/gas with respect to water, thus preventing water banking behind the formation surface;
(i) the well is a retrograde condensate gas reservoir and the surface modifying treatment agent minimizes condensation within the reservoir while maintaining the permeability of the reservoir;
(j) the well is a gas or oil well and the surface modifying treatment agent enhances the amount of flowback water and produced water from the well following completion of a well treatment operation;
(k) the surface modifying treatment agent is within a pad fluid;
(l) the surface modifying treatment agent is within a well treatment fluid and the well treatment fluid is pumped into the well at a pressure sufficient to create or enlarge a fracture in the subterranean formation;
(m) the surface modifying treatment agent is dispersed in a well treatment fluid;
(n) the surface modifying treatment agent controls water condensation in the pores of the near wellbore region of the subterranean formation;
(o) the formation is a tar sand formation and the surface modifying treatment agent enhances the recovery of hydrocarbons from deposits within the tar sand;
(p) the subterranean formation is subjected to acidizing and the surface modifying treatment agent increases the penetration of acid into the formation; or
(q) the subterranean formation is a matrix formation and the surface modifying treatment agent reduces the influx of water into the formation.

17. The method of claim 2 , wherein the subterranean formation is a carbonate formation or a sandstone formation.

18. The method of claim 2 , wherein the metal oxide-containing formation contains aluminum.

19. The method of claim 2 , wherein step (b) comprises binding the surface modifying treatment agent to a surface of the subterranean formation by forming either (i) a O—Y—O—Si covalent bond between the anchor and a siliceous formation; or (ii) a O—Y—O-M covalent bond between the anchor and a metal oxide-containing formation wherein Y is the metal of the metallic anchor and M is the metal of the metal oxide-containing formation.

20. The method of claim 19 , further comprising reducing drag of a fluid within the well.

21. The method of claim 20 , wherein t

Assignees

• Baker Hughes Inc

Inventors

• Lant Kimberly
• Bestaoui-Spurr Naima
• Bhaduri Sumit
• Crews James B
• Le Hoang
• Monroe Terry D
• Qu Qi

Classifications

• C09K8/60 Primary

  Compositions for stimulating production by acting on the underground formation · CPC title

• C09K8/58

  Compositions for enhanced recovery methods for obtaining hydrocarbons, i.e. for improving the mobility of the oil, e.g. displacing fluids · CPC title

• C09K8/584 Primary

  characterised by the use of specific surfactants · CPC title

• E21B43/16 Primary

  Enhanced recovery methods for obtaining hydrocarbons · CPC title

• E21B43/27

  by use of eroding chemicals, e.g. acids · CPC title