Methods and systems for design and/or selection of drilling equipment based on wellbore drilling simulations

• US 8,352,221 B2
• Filed: 11/02/2010
• Issued: 01/08/2013
• Est. Priority Date: 08/08/2005
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Chen, Shilin
• Primary Examiner(s): Craig, Dwin M
• Application Number:
  US12/938,151
• Publication Number:
  US 20110077928A1
• Time in Patent Office: 798 Days
• Field of Search: 703/10, 703/1, 702/9
• US Class Current: 703/1
• CPC Class Codes: E21B 10/00 Drill bits specially adapted for deflecting the direction of boring E21B7/064; with means for collecting substances E21B27/00
• CPC Class Codes: E21B 41/00 Equipment or details not covered by groups E21B15/00 - E21B40/00
• CPC Class Codes: E21B 44/00 Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
• CPC Class Codes: E21B 49/003 by analysing drilling variables or conditions E21B49/005 takes precedence; systems specially adapted for monitoring a plurality of drilling variables or conditions E21B44/00
• CPC Class Codes: E21B 7/04 Directional drilling
• CPC Class Codes: E21B 7/06 Deflecting the direction of boreholes
• CPC Class Codes: E21B 7/064 specially adapted drill bits therefor

Abstract

Methods and systems may be provided for simulating forming a wide variety of directional wellbores including wellbores with variable tilt rates and/or relatively constant tilt rates. The methods and systems may also be used to simulate forming a wellbore in subterranean formations having a combination of soft, medium and hard formation materials, multiple layers of formation materials and relatively hard stringers disposed throughout one or more layers of formation material.

Claims

1. A method of optimizing drilling parameters for a portion of a wellbore using a rotary drill bit, the method comprising:

inputting wellbore data and formation data corresponding with the portion of the wellbore;

inputting drilling equipment data, including rotary drill bit parameters and bottom hole assembly parameters;

simulating drilling the portion of the wellbore multiple times with various combinations of drilling parameters using the drilling equipment data, the wellbore data, and the formation data;

the drilling parameters including at least bit rotational speed and either weight on bit or rate of penetration;

calculating a set of bit forces resulting from each of the various combinations of drilling parameters, the set of bit forces including at least one force selected from the group consisting of steer force, walk force, axial force, lateral imbalance force, and torque;

calculating a drilling difficulty based on the resulting bit forces; and

identifying the combination of drilling parameters with the lowest drilling difficulty.

2. A method according to claim 1, wherein the drilling equipment includes drilling equipment for use with a push-the-bit directional drilling system.

3. A method according to claim 1, wherein the drilling equipment includes drilling equipment for use with a point-the-bit directional drilling system.

4. A method according to claim 1, wherein the drilling difficulty includes at least one metric selected from the group consisting of:

steering difficulty, steerability, controllability, fluctuation in torque on bit, fluctuation in bit bending moment, and fluctuation in bit side force.

5. A method according to claim 1, wherein the drilling difficulty includes at least a steering difficulty for the rotary drill bit based at least in part on side forces calculated as a function of the steer rate applied to the rotary drill bit.

6. A method of simulating drilling a directional wellbore comprising:

dividing a planned directional wellbore into portions selected from the group consisting of;

straight hole portion, kick-off portion and equilibrium portion;

inputting drilling equipment data, including bit design data;

inputting formation data;

inputting wellbore data and formation data corresponding with one or more portions of the wellbore;

simulating drilling each of the one or more portions of the wellbore multiple times with various combinations of drilling parameters using the drilling equipment data, the wellbore data, and the formation data;

the drilling parameters including at least bit rotational speed and either weight on bit or rate of penetration;

calculating a set of bit forces resulting from each of the various combinations of drilling parameters;

calculating a drilling difficulty based on the resulting bit forces; and

identifying the combination of drilling parameters with the lowest drilling difficulty for each of the one or more portions of the wellbore.

7. A method according to claim 6, wherein the drilling difficulty includes at least one metric selected from the group consisting of:

steering difficulty, steerability, controllability, fluctuation in torque on bit, fluctuation in bit bending moment, and fluctuation in bit side force.

8. A method according to claim 6, wherein the set of bit forces includes at least one force selected from the group consisting of:

steer force, walk force, axial force, lateral imbalance force, and torque.

9. A method according to claim 6, wherein the drilling difficulty includes at least a steering difficulty for the rotary drill bit based at least in part on side forces calculated as a function of the steer rate applied to the rotary drill bit.

10. A method according to claim 6, wherein simulating drilling further comprises:

calculating all forces acting on the bit resulting from drilling, including forces acting on each cutter and each gage of the bit;

projecting the calculated forces into a bit coordinate system which rotates with the bit; and

projecting the calculated forces into a hole coordinate system which is fixed with the formation.

11. A method according to claim 6, wherein inputting formation data further comprises:

inputting strength of a first layer and a second layer; and

inputting an inclination angle between the first layer and the second layer.

12. A method according to claim 6, further comprising using the identified combination of drilling parameters to drill the corresponding portion of the wellbore.

13. A method according to claim 6, wherein the drilling equipment includes a push-the-bit directional drilling system.

14. A method according to claim 6, wherein the drilling equipment includes a point-the-bit directional drilling system.

15. A method for selecting a rotary bit for drilling at least a portion of a wellbore, the method comprising:

inputting wellbore data and formation data corresponding with the portion of the wellbore;

inputting drilling equipment data, including rotary drill bit parameters for at least two rotary bits;

simulating drilling the portion of the wellbore using the drilling equipment data, the wellbore data, and the formation data;

the drilling parameters including at least bit rotational speed and either weight on bit or rate of penetration;

calculating a set of bit forces resulting from each of the at least two bits, the set of bit forces including at least one force selected from the group consisting of steer force, walk force, axial force, lateral imbalance force, and torque;

calculating a drilling difficulty for each of the at least two rotary bits based on the resulting bit forces; and

identifying the rotary bit having the lowest drilling difficulty.

16. A method according to claim 15, wherein the drilling equipment includes drilling equipment for use with a push-the-bit directional drilling system.

17. A method according to claim 15, wherein the drilling equipment includes drilling equipment for use with a point-the-bit directional drilling system.

18. A method according to claim 15, wherein the drilling difficulty includes at least one metric selected from the group consisting of:

steering difficulty, steerability, controllability, fluctuation in torque on bit, fluctuation in bit bending moment, and fluctuation in bit side force.

19. A method according to claim 15, wherein the drilling difficulty includes at least a steering difficulty for the rotary drill bit based at least in part on side forces calculated as a function of the steer rate applied to the rotary drill bit.