Method of Monitoring Fluid Placement During Stimulation Treatments

• US 20070095528A1
• Filed: 10/20/2006
• Published: 05/03/2007
• Est. Priority Date: 11/02/2005
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Lovell, John, Jiang, Li, Raghuraman, Bhavani, Ziauddin, Murtaza, Hill, Stephen, Schroeder, Robert, Espinosa, Frank, Sun, Xuefei, Andrews, Ballard, Fremont, Sebastien, Afroz, Mahmuda, Davies, Steve, Orlet, Michael
• Granted Patent: US 7,658,226 B2
• Time in Patent Office: Days
• US Class Current: 166/252.3
• CPC Class Codes: E21B 43/25 Methods for stimulating production by vibrating earth formations E21B43/003
• CPC Class Codes: E21B 47/10 Locating fluid leaks, intrusions or movements
• CPC Class Codes: G01F 1/704 using marked regions or existing inhomogeneities within the fluid stream, e.g. statistically occurring variations in a fluid parameter G01F1/76, G01F25/00 take precedence
• CPC Class Codes: G01F 1/7086 using optical detecting arrangements

Abstract

Although the methods have been described here for, and are most typically used for, hydrocarbon production, fluid diversion measurement systems and methods are described. One method includes inserting a tubular tubing having one more fluid injection ports into a wellbore, injecting a treatment fluid through the injection port, and determining differential flow of the treatment fluid at one or more wellbore based on measuring the concentration of at least one particular component of a wellbore fluid located in the annulus formed between the wellbore and tubular; and means for using the measured parameters in realtime to monitor, control, or both monitor and control diversion of the fluid. This abstract allows a searcher or other reader to quickly ascertain the subject matter of the disclosure. It will not be used to interpret or limit the scope or meaning of the claims. 37 CFR 1.72(b).

Claims

1. A method comprising:

(a) inserting a tubular into a wellbore, the tubular comprising a section of tubing having at least one fluid injection port;

(b) injecting a treatment fluid through the at least one fluid injection port; and

(c) determining differential flow of the treatment fluid at one or more wellbore intervals based on measuring pH of wellbore fluid located in the annulus formed between the wellbore and tubular.

2. The method of claim 1 comprising measuring flow out of the tubular.

3. The method of claim 1 comprising measuring flow out upstream and downstream from the at least one injection port.

4. The method of claim 1 wherein the tubular is selected from coiled tubing and sectioned pipe, wherein sections of the sectioned pipe may be joined by means selected from welds, threaded fittings, flanged fittings, and combinations thereof.

5. The method of claim 1 wherein the injecting of the fluid is through the tubular to a bottom hole assembly attached to the distal end of the tubular.

6. The method of claim 1 wherein the pH is measured at a plurality of points upstream and downstream of the of the injection point.

7. The method of claim 1 comprising executing a pre-job fluid diversion design in realtime.

8. The method of claim 7 comprising activities selected from evaluating, modifying, and programming the fluid diversion design in realtime.

9. The method of claim 1 comprising controlling the injecting of the fluid via one or more flow control devices and/or fluid hydraulic techniques to divert and/or place the fluid into a desired location that is determined by objectives of an operator or owner.

10. The method of claim 1 wherein the injecting of the fluid occurs while the section of tubular is stationary or moving in the wellbore.

11. A method for stimulating a subterranean formation, the method comprising introducing a treatment fluid into a wellbore, and monitoring the diversion of the treatment into the reservoir by providing a plurality of sensors which measure the concentration of at least one wellbore fluid component, wherein the sensors are disposed on a support adapted to maintain a given spacing between the sensors.

12. The method of claim 11, further comprising adjusting the composition of the fluids and injection rates pressure of the fluid in response to the measure of concentration of at least one wellbore fluid component.

13. The method of claim 12, wherein the adjusting step is made in real time.

14. The method according to claim 11, wherein the composition of the treatment fluids is modified at the surface in response to the measure of concentration of at least one wellbore fluid component.

15. The method according to claim 11, wherein the composition of the treatment fluids is modified downhole in response to the measure of proton concentration.

16. The method according to claim 11, wherein the composition of the treatment fluids is modified downhole in response to the measure of fluorescent dye concentration.

17. The method according to claim 11, wherein the composition of the treatment fluids is modified by mixing with reservoir fluids.

18. The method according to claim 11, wherein the support of sensors is provided by a coiled tubing.

19. The method according to claim 11, wherein the support of sensors is provided by a wireline cable.

20. A method comprising:

(a) inserting a tubular into a wellbore, the tubular comprising a section of tubing having at least one fluid injection port;

(b) injecting a treatment fluid through the at least one fluid injection port; and

(c) determining differential flow of the treatment fluid at one or more wellbore intervals by measuring fluorescence of wellbore fluid located in the annulus formed between the wellbore.