Use of Micro-Electro-Mechanical Systems (MEMS) in Well Treatments

• US 20110192597A1
• Filed: 02/21/2011
• Published: 08/11/2011
• Est. Priority Date: 04/02/2007
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Covington, Rick, Bonavides, Clovis, Ravi, Krishna M., RODDY, Craig W., Frisch, Gary, Mandal, Batakrishna
• Granted Patent: US 8,162,050 B2
• Time in Patent Office: Days
• US Class Current: 166/253.1
• CPC Class Codes: E21B 33/13 Methods or devices for cementing, for plugging holes, crevices or the like
• CPC Class Codes: E21B 43/25 Methods for stimulating production by vibrating earth formations E21B43/003
• CPC Class Codes: E21B 47/005 Monitoring or checking of cementation quality or level
• CPC Class Codes: E21B 47/01 Devices for supporting measuring instruments on drill bits, pipes, rods or wirelines; Protecting measuring instruments in boreholes against heat, shock, pressure or the like
• CPC Class Codes: E21B 47/10 Locating fluid leaks, intrusions or movements
• CPC Class Codes: E21B 47/13 by electromagnetic energy, e.g. radio frequency

Abstract

A method of servicing a wellbore, comprising placing a plurality of Micro-Electro-Mechanical System (MEMS) sensors in a wellbore composition, pumping the wellbore composition into the wellbore at a flow rate, determining velocities of the MEMS sensors along a length of the wellbore, and determining an approximate cross-sectional area profile of the wellbore along the length of the wellbore from at least the velocities of the MEMS sensors and the fluid flow rate. A method of servicing a wellbore, comprising placing a plurality of Micro-Electro-Mechanical System (MEMS) sensors in a wellbore composition, pumping the wellbore composition into the wellbore, determining positions of the MEMS sensors relative to one or more known positions along a length of the wellbore, and determining an approximate cross-sectional area profile of the wellbore along the length of the wellbore from at least the determined positions of the MEMS sensors.

Claims

1. A method of servicing a wellbore, comprising:

placing a plurality of Micro-Electro-Mechanical System (MEMS) sensors in a wellbore composition;

pumping the wellbore composition into the wellbore at a flow rate;

determining velocities of the MEMS sensors along a length of the wellbore; and

determining an approximate cross-sectional area profile of the wellbore along the length of the wellbore from at least the velocities of the MEMS sensors and the fluid flow rate.

2. The method of claim 1, wherein a constriction in the wellbore is determined in a region of the wellbore in which average velocities of the MEMS sensors exceed a threshold average velocity.

3. The method of claim 2, wherein the threshold average velocity is determined using the fluid flow rate of the wellbore composition and an expected cross-sectional area.

4. The method of claim 3, wherein the expected cross-sectional area is based upon a desired wellbore diameter and a known casing size.

5. The method of claim 2, wherein the average velocities of the MEMS sensors return to a value below the threshold average velocity after the MEMS sensors traverse the constriction.

6. The method of claim 1, wherein an expansion in the wellbore is determined in a region of the wellbore in which average velocities of the MEMS sensors fall below a threshold average velocity.

7. The method of claim 6, wherein the threshold average velocity is determined using the fluid flow rate of the wellbore composition and an expected cross-sectional area.

8. The method of claim 6, wherein the average velocities of the MEMS sensors return to a value above the threshold average velocity after the MEMS sensors traverse the expansion.

9. The method of claim 1, wherein a fluid loss zone is determined in a region of the wellbore in which average velocities of the MEMS sensors fall below, and remain below, a threshold average velocity.

10. The method of claim 9, further comprising determining a return fluid flow rate of the wellbore composition from the wellbore, wherein the fluid loss zone is additionally characterized using the return fluid flow rate of the wellbore composition.

11. The method of claim 1, further comprising determining positions of the MEMS sensors relative to one or more known positions along a length of the wellbore, wherein the determining of the approximate cross-sectional area profile of the wellbore along the length of the wellbore is further based upon the determined positions of the MEMS sensors.

12. The method of claim 11, further comprising determining shapes of wellbore cross- sections along the length of the wellbore using positions of the MEMS sensors detected as the MEMS sensors traverse the wellbore cross-sections.

13. The method of claim 11, wherein the positions of the MEMS sensors in the wellbore, the velocities of the MEMS sensors along the length of the wellbore, and/or the approximate cross- sectional area profile of the wellbore are determined at least approximately in real time.

14. The method of claim 11, wherein the positions and/or velocities of the MEMS sensors in the wellbore are determined using a plurality of data interrogation units spaced along the length of the wellbore.

24. The method of claim 1, wherein the wellbore composition comprises a drilling fluid, a spacer fluid, a sealant, a fracturing fluid, a gravel pack fluid, or a completion fluid.

15. A method of servicing a wellbore, comprising:

placing a plurality of Micro-Electro-Mechanical System (MEMS) sensors in a wellbore composition;

pumping the wellbore composition into the wellbore;

determining positions of the MEMS sensors relative to one or more known positions along a length of the wellbore; and

determining an approximate cross-sectional area profile of the wellbore along the length of the wellbore from at least the determined positions of the MEMS sensors.

16. The method of claim 15, wherein the one or more known positions correspond to the location of one or more data interrogation units.

17. The method of claim 16, wherein the known positions correspond to casing collar locations.

18. The method of claim 16, wherein the data interrogation units provide positional information of the MEMS sensors in x, y, and z coordinates relative to an orientation of the data interrogation units.

19. The method of claim 15, wherein the wellbore composition is a cement composition that has formed a cement sheath in the wellbore, and further comprising determining whether the cement sheath requires a remedial service based at least in part on the approximate cross-sectional area profiles.

20. A method of servicing a wellbore, comprising:

placing a plurality of Micro-Electro-Mechanical System (MEMS) sensors in a sealant;

placing the sealant in an annulus disposed between a wall of the wellbore and a casing positioned in the wellbore;

allowing the sealant to cure to form a sealant sheath;

determining spatial coordinates of the MEMS sensors with respect to the casing; and

mapping planar coordinates of the MEMS sensors in a plurality of cross-sectional planes.

21. A method of servicing a wellbore, comprising:

placing a plurality of Micro-Electro-Mechanical System (MEMS) sensors in a wellbore composition, wherein one or more of the MEMS sensors is uniquely identified;

pumping the wellbore composition into the wellbore at a flow rate;

determining positions of the uniquely identified MEMS sensors relative to one or more known positions along a length of the wellbore; and

determining a decrease in the flow rate of the wellbore composition based upon the positions of the uniquely identified MEMS sensors.

22. The method of claim 21, wherein determining a decrease in the flow rate of the wellbore composition based upon the positions of the uniquely identified MEMS sensors further comprises detecting a first amount of the uniquely identified MEMS during a first sampling period at a first location in the wellbore and detecting a second amount of the same uniquely identified MEMS during a second sampling period at a second location in the wellbore, wherein the second amount is less than the first amount.

23. The method of claim 22, further comprising measuring a first average MEMS sensor velocity at the first location and a second average MEMS sensor velocity at the second location, and wherein the second average MEMS sensor velocity is less than the first average MEMS sensor velocity.