METHODS FOR OBTAINING A WELLBORE SCHEMATIC AND USING SAME FOR WELLBORE SERVICING

• US 20070277975A1
• Filed: 05/31/2006
• Published: 12/06/2007
• Est. Priority Date: 05/31/2006
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Lovell, John R., Kane, Moussa
• Granted Patent: US 7,857,046 B2
• Time in Patent Office: Days
• US Class Current: 166/250.10
• CPC Class Codes: E21B 47/04 Measuring depth or liquid level

Abstract

Methods are described for determining or estimating a wellbore schematic, one embodiment comprising running one or more measured distances of coiled tubing into a wellbore while pumping a fluid at varying flow rates through the coiled tubing, and calculating true vertical depth of the wellbore using pressure and flow rate data of the fluid. This abstract allows a searcher or other reader to quickly ascertain the subject matter of the disclosure. It may 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) providing a coil of coiled tubing having a length able to reach a determined section of a wellbore;

(b) running one or more measured distances of the coiled tubing into the wellbore while pumping a fluid at varying flow rates through the coiled tubing;

(c) measuring circulating pressure and pressure at bottom of the wellbore at various times during running and pumping; and

(d) calculating wellbore parameters at the one or more measured distances using the pressure and flow rate data.

2. The method of claim 1 wherein the wellbore parameters include true vertical depth of the wellbore along the length of said wellbore.

3. The method of claim 2 comprising cross-plotting the true vertical depth versus the measured distances as a function of time.

4. The method of claim 1 comprising pumping a sequence of fluids through the coiled tubing at known circulating pressures and flow rates, sending bottom-hole data to the surface, and fitting the data to estimate a wellbore schematic assuming a minimal radius of curvature for the wellbore.

5. The method of claim 1 comprising monitoring density of the fluid during pumping with or without calculating or estimating friction pressure of the fluid using the circulating pressure and the hydrostatic pressure.

6. The method of claim 1 comprising transmitting real-time wellbore pressure data to the surface using one or more methods selected from wireless methods, wire methods via a data-carrying wire, fiber-optic lines, and combinations thereof.

7. The method of claim 6 comprising supplying the coiled tubing to a well site spooled onto a reel, selected from a communication line already inserted into the spool, and inserting a communication line into the coiled tubing at the well site.

8. The method of claim 7 comprising modeling friction pressure in the coiled tubing as two components:

friction pressure=A₁*(flow rate)ⁿ¹+A₂*(flow rate)ⁿ²

where the first term to the right of the equal sign represents the pressure drop along that part of the coil spooled onto the reel, the second term to the right to the equal sign represents the pressure drop along the unspooled coil, n1 and n2 are exponents ranging from about 1 to about 2, and A₁ and A₂ depend on viscosity of the fluid, local friction effects and internal diameter of the coiled tubing.

9. The method of claim 8 comprising modeling circulation pressure wherein a total of L_T feet of coiled tubing is brought to the wellhead and MD(t) has been run into the wellbore at time t, and the friction pressure is modeled as:

friction pressure=a₁*(L_T−

MD(t))*(flow rate(t))ⁿ¹+a₂*MD(t)*(flow rate(t))ⁿ²

where unknown coefficients a₁ and a₂, and unknown exponents n1 and n2 are estimated by varying the flow rate and MD during the time the coiled tubing is running in.

10. The method of claim 9 comprising assuming the fluid density remains constant so that hydrostatic pressure=TVD(t)*density*g

11. The method of claim 9 comprising assuming the fluid density is changing with wellbore depth into a vertical wellbore, measuring a difference between fluid pressure just outside a terminus of the coiled tubing (P_an) and pressure at an annulus exit at the wellhead (WHP), and calculating fluid density using the equation:

12. The method of claim 9 comprising assuming the fluid density is changing with wellbore depth in a wellbore having a vertical portion and a deviated portion, measuring a difference between fluid pressure just outside a terminus of the coiled tubing (P_an) and pressure at an annulus exit at the wellhead (WHP), and calculating fluid density using the equation:

13. The method of claim 1 comprising measuring bottom-hole pressure without a downhole electronics package.

14. The method of claim 1 comprising repeating steps (b), (c), and (d) during repeated passes of the tubing through the wellbore.

15. The method of claim 1 wherein the running one or more measured distances of the coiled tubing into the wellbore comprises running into wellbores selected from substantially vertical wellbores, deviated wellbores, and combinations thereof.

16. A method comprising:

(a) pumping a fluid at a wellhead down a wellbore through coiled tubing and measuring pressure and flow rate of the fluid at the wellhead and down the wellbore at a terminus of the coiled tubing, the fluid flowing out of the wellbore through an annulus; and

(b) monitoring presence of particles in the fluid with or without detecting variations in their concentration.

17. The method of claim 16 comprising monitoring variations in density of the fluid at an entrance to the annulus with or without calculating fluid density at the annulus entrance.

18. The method of claim 16 comprising quantifying an amount of solid material removed from the wellbore by the fluid with or without monitoring efficiency of the fluid in carrying the solid material to the surface.

19. The method of claim 18 comprising determining a quantity f*k_geo in respective vertical and diverted portions of the wellbore, wherein f is the friction coefficient and k_geo is a constant that depends on geometry of the annulus, and calculating density of the fluid in the annulus using the quantity, the quantity determined by methods selected from 1) calculating the quantity from flow data obtained before any solid materials enter the fluid;

2) periodically stopping fluid flow for short time periods;

     3) plotting a difference between annulus pressure and wellhead pressure as a function of length of tubing in the wellbore, with a set of pre-defined constant density lines, and combinations of these methods.

20. The method of claim 16 wherein the pumping a fluid at a wellhead down a wellbore comprises pumping the fluid into wellbores selected from substantially vertical wellbores, deviated wellbores, and combinations thereof.

21. A method comprising:

(a) running one or more measured distances of coiled tubing into a wellbore while pumping a fluid at varying flow rates through the coiled tubing; and

(b) calculating true vertical depth of the wellbore using pressure and flow rate data of the fluid.

22. A method of stimulating a reservoir being drained by a multilateral well system, comprising:

(a) penetrating a multilateral well system with coiled tubing;

(b) pumping fluids into said coiled tubing;

(c) making measurements of downhole parameters;

(d) inferring trajectory of the coiled tubing from at least some of the parameters;

(e) determining which lateral of the multilateral well system is being penetrated by the coiled tubing; and

(f) pumping stimulation fluid into the lateral being penetrated.

23. The method of claim 22 comprising selecting the stimulation fluid based upon which lateral has been penetrated.

24. The method of claim 22 wherein the parameters comprise a pressure selected from wellhead pressure, circulation pressure, annulus bottom hole pressure, coiled tubing bottom hole pressure, and any two or more of these.

25. The method of claim 22 comprising sending real-time pressure data to the surface during the pumping of stimulation fluid using one or more methods selected from wireless telemetry methods, wire telemetry methods, and fiber-optic telemetry methods, wherein the fiber-optic methods are selected from (a) running one or more fiber-optic lines into the coiled tubing, and b) pre-loading one or more fiber-optic lines into a coil of coiled tubing at the surface prior to penetrating the multilateral well system.

26. The method of claim 24 wherein the coiled tubing bottom hole pressure is converted into true vertical depth and the trajectory is determined as a function of true vertical depth versus penetration length of the coiled tubing into the lateral being penetrated.