Method of treating a subterranean formation using a rheology model for fluid optimization

• US 7,784,544 B2
• Filed: 01/19/2007
• Issued: 08/31/2010
• Est. Priority Date: 01/24/2006
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: Parris, Michael D., Ziauddin, Murtaza, Lindvig, Thomas
• Primary Examiner(s): Bates; Zakiya W
• Assistant Examiner(s): DiTrani; Angela M
• Application Number:
  US11/625,105
• Publication Number:
  US 20070169932A1
• Time in Patent Office: 1,320 Days
• Field of Search: 702/6, 702/11, 702/12, 703/9, 703/10
• US Class Current: 166/305.1
• CPC Class Codes: C09K 2208/08 Fiber-containing well treatment fluids
• CPC Class Codes: C09K 8/52 Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
• CPC Class Codes: C09K 8/685 containing cross-linking agents
• CPC Class Codes: C09K 8/74 combined with additives added for specific purposes

Abstract

Subterranean formation treatment methods incorporating a rheology model which enables prediction of fluid rheology properties during a treatment operation, where the foundation of the model is a description of the reaction chemistry which describes how the number of crosslinks and broken polymer linkages develops in time under the influence of crosslinkers, breakers, and/or thermally induced effects and pressure effects. In one aspect, when used as a tool for simulating the fluid viscosity, the model can help optimizing the fluid design and optional breaker schedule for a hydraulic fracturing treatment.

Claims

1. A method for treating a subterranean formation penetrated by a wellbore, the method comprising:

a. predicting a plurality of formation treatment scenarios for a treatment fluid comprising a polymer and a crosslinker using a fluid rheology model comprising;

i. inputting a concentration of polymer and a concentration of crosslinker,

ii. inputting temperature, formation pressure, and shear rate profiles over the course of the treatment,

iii. determining a concentration of crosslinks over the course of the treatment based upon the input values from i. and ii, and

iv. determining the fluid rheology over the course of the treatment based on the concentration of crosslinks over the course of the treatment;

b. selecting a treatment scenario from the plurality of formation treatment scenarios which provides fluid rheology properties during the course of treatment;

c. preparing and injecting the treatment fluid into the wellbore; and

,

d. treating the subterranean formation.

2. The method of claim 1 further comprising inputting a concentration of breaker.

3. The method of claim 1 further comprising inputting the concentration of one or more pH modifiers over the course of the treatment.

4. The method of claim 1 wherein in the selection of a treatment scenario is based upon incorporating a concentration of polymer.

5. The method of claim 4 wherein in the selection of a treatment scenario is based upon incorporating a concentration of polymer and optimal clean-up after treatment.

6. The method of claim 1 further comprising inputting a concentration of a crosslinking delay agent over the course of the treatment.

7. The method of claim 1 further comprising monitoring the treatment fluid and evaluating the fluid performance downhole based upon real-time monitoring of the fluid composition at the surface.

8. The method of claim 1 further comprising inputting fluid pumping rate, wellbore configuration, and fluid travel time to a treatment zone.

9. The method of claim 1 as used in a hydraulic fracturing simulator whereby fluid rheology is calculated to simulate the fracture placement and an optimal pumping sequence is determined.

10. The method of claim 1 wherein the fluid rheology is determined by coupling irreversible reactions that the polymer undergoes caused by thermal effects or by oxidizing or enzyme agent, with equilibrium reactions of the crosslinker and polymer as a function of time, temperature, pressure, polymer concentration, and crosslinker concentration.

11. The method of claim 1 as used for fracturing a subterranean formation.

12. The method of claim 1 as used for monitoring fluid placement during a treatment selected from the group consisting of fracturing treatments, acidizing treatments, wellbore cleanout operations, gravel packing operations, acid diversion treatments, and fluid loss control operations.

13. The method of claim 1 wherein the polymer is selected from the group consisting of guar, hydropropyl guar (HPG), carboxymethyl guar (CMG), carboxymethylhydroxypropyl guar, cellulose, hydroxyethylcellulose (HEC), hydroxypropylcellulose (HPC), carboxymethylhydroxyethylcellulose (CMHEC), xanthan, diutan, whelan gum, polyacrylamide, polyacrylate polymers, and wherein the crosslinker is a zirconium, titanium or borate based crosslinker.

14. The method of claim 1 wherein the polymer is guar and the crosslinker is a borate based crosslinker.

15. The method of claim 1 further comprising considering pressure effects on the effectiveness of a borate based crosslinker in determining the fluid rheology over the course of the treatment.

16. The method of claim 1 wherein the concentration of crosslinks is about 5×

10<sup>−

8</sup> mole/L or greater.

17. The method of claim 1 wherein the fluid further comprises a proppant, and concentration of the proppant is inputted into the model.

18. The method of claim 1 wherein the concentration of polymer ranges from about 15 to about 40 pounds per thousand gallons.

19. The method of claim 1 wherein the concentration of polymer is about 15 pounds per thousand gallons or less.

20. A method for treating a subterranean formation penetrated by a wellbore, the method comprising:

a. predicting a plurality of formation treatment scenarios for a fluid comprising a polymer, using a fluid rheology model comprising;

i. inputting a concentration of polymer,

ii. inputting temperature, formation pressure and shear rate profiles over the course of the treatment, and

iii. determining the fluid rheology over the course of the treatment by considering concentration of polymer, and temperature, pressure and shear rate profiles over the course of the treatment;

b. selecting a treatment scenario from the plurality of formation treatment scenarios which provides fluid rheology properties during the course of treatment;

c. preparing and injecting the treatment fluid into the wellbore; and

,

d. treating the formation.