Methods and systems for designing and/or selecting drilling equipment using predictions of rotary drill bit walk

• US 8,606,552 B2
• Filed: 10/19/2012
• Issued: 12/10/2013
• 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): PHAN, THAI Q
• Application Number:
  US13/656,527
• Publication Number:
  US 20130043077A1
• Time in Patent Office: 417 Days
• Field of Search: 703/2, 703/7, 703/10, 700/117, 175/24, 175/45, 175/341, 175/406
• US Class Current: 703/2
• 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 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. Values of bit walk rate from such simulations may be used to design and/or select drilling equipment for use in forming a directional wellbore.

Claims

1. A method to design a rotary drill bit with a desired bit walk rate comprising:

(a) determining the drilling conditions and the formation characteristics to be drilled by the bit;

(b) simulating drilling at least one portion of a wellbore using the drilling conditions;

(c) calculating the average bit walk rate;

(d) comparing the calculated bit walk rate to the desired walk rate;

(e) if the calculated walk rate does not approximately equal the desired walk rate, modifying at least one bit geometry of the rotary drill bit selected from the group consisting of bit profile, cutter location, cutter orientation, cutter density, gauge length, gage diameter; and

(f) repeating steps (a) through (e) until the calculated walk rate approximately equals the desired walk rate.

2. The method of claim 1 further comprising:

checking the calculation of the walk rate by changing at least one of the drilling conditions; and

repeating steps (a) to (e), if necessary.

3. The method of claim 1 further comprising designing an energy balanced fixed cutter drill bit.

4. The method of claim 1 further comprising calculating the walk rate using walk force and steer force, and calculating the walk rate using walk moment and steer moment.

5. A method to select a rotary drill bit to drill at least one portion of a wellbore having at least one desired trajectory comprising:

(a) determining a desired walk rate to compensate for the desired trajectory of the at least one portion of the wellbore;

(b) determining at least one formation property of the at least one portion of the wellbore;

(c) determining a first set of bit operational parameters according to capability of an associated drilling system and experience gained by drilling other wellbores with similar formation properties;

(d) choosing a first rotary drill bit;

(e) calculating a walk rate for the first rotary drill bit under the first set of bit operational parameters and comparing the calculated walk rate with the desired walk rate;

(f) choosing a second rotary drill bit; and

(g) repeating steps (e) and (f) until the calculated walk angle for at least one rotary drill bit is approximately equal to the desired walk rate under the first set of bit operational parameters.

6. The method of claim 5 further comprising:

monitoring the trajectory of the at least one rotary drill bit during simulated drilling of the at least one portion of the wellbore; and

if the simulated trajectory of the at least one rotary drill bit does not correspond with the desired trajectory, finding an optimal set of bit operational parameters by repeating steps (c) through (g) of claim 5 for the at least one rotary drill bit.

7. The method of claim 5 further comprising selecting a fixed cutter rotary drill bit from existing fixed cutter rotary drill bit designs.

8. A method for designing a rotary drill bit having a gauge comprising:

(a) determining formation properties such as transition layer strength and inclination angle for use in simulating drilling with the rotary drill bit;

(b) determining drilling conditions for use in simulating drilling with the rotary drill bit;

(c) determining if the rotary drill bit will be used with a point-the-bit or push-the-bit drilling system;

(d) simulating applying a steering motion, a relative shorter bent length, axial penetration and rotation forces to the rotary drill bit when used with a point-the-bit drilling system;

(e) simulating applying steering motion, a relative longer bent length, axial penetration and rotation forces to the rotary drill bit when used with a push-the-bit drilling system;

(f) calculating a walk rate based on the simulated drilling;

(g) comparing the calculated walk rate with a desired walk rate;

(h) if the calculated walk rate is not approximately equal to the desired walk rate, changing a bit geometry such as bit profile, cutter locations and orientations, cutter density or changing a geometric parameter of the gauge such as gauge length, gauge radius, gauge taper angle and gauge blade spiral angle; and

(i) repeating steps (c) to (h) until the calculated walk rate approximately equals the desired walk rate.

9. The method of claim 8 further comprising:

checking the calculation of the walk rate by changing at least one drilling condition according to variations of actual drilling conditions; and

repeating step (c) to (h) of claim 8, if necessary.

10. The method of claim 8 further comprising calculating the walk rate based on steer force and walk force.

11. The method of claim 8 further comprising calculating the walk rate based on steer moment and walk moment.

12. The method of claim 8 further comprising calculating the walk rate based on an average of the walk rate calculated from steer force and walk force, and the walk rate calculated from steer moment and walk moment.

13. A rotary drill bit with desired walk characteristics comprising:

a bit face profile designed for use in a directional drilling system;

the bit face profile defined in part by a plurality of blades with a plurality of cutters disposed on each blade;

the bit face profile further defined by a recessed portion disposed on one end of the rotary drill bit;

a nose disposed adjacent to the recessed portion with a shoulder portion extending outward from the nose portion;

a plurality of inner cutters disposed within the recessed portion and a plurality of cutters disposed on the shoulder portion of the rotary drill bit; and

the ratio between the number of inner cutters and the number of outer cutters based upon calculation and comparison of various walk rates for the rotary drill bit corresponding with respective ratios of inner cutters and shoulder cutters.

14. The drill bit of claim 13 further comprising:

a gage portion disposed on the exterior of the rotary drill bit adjacent to the shoulder portion;

a plurality of gage cutters disposed on the blades adjacent to the gage portion; and

the number, location and type of gage cutters based upon comparing the results of one or more simulations of forming a directional wellbore using the rotary drill bit.

15. The drill bit of claim 13 further comprising a passive gage portion having a negative taper angle optimized for use in forming a directional wellbore.

16. The drill bit of claim 13 further comprising the bit face profile providing means for optimizing use of the drill bit with a push-the-bit steerable drilling system.

17. The drill bit of claim 13 further comprising the bit face profile providing means for optimizing use of the drill bit with a point the bit steerable drilling system.