Methods and Systems to Predict Rotary Drill Bit Walk and to Design Rotary Drill Bits and Other Downhole Tools

• US 20090090556A1
• Filed: 12/12/2008
• Published: 04/09/2009
• Est. Priority Date: 08/08/2005
• Status: Active Grant

• Current Assignee: Halliburton Energy Services Incorporated (Halliburton Company), Ip Ot Sub Ulc, OT IP SUB, LLC
• Original Assignee: Halliburton Energy Services Incorporated (Halliburton Company)
• Inventors: Chen, Shilin
• Granted Patent: US 7,860,696 B2
• Time in Patent Office: Days
• US Class Current: 175/45
• 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 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 7/04 Directional drilling

Abstract

Methods and systems may be provided to simulate forming a wide variety of directional wellbores including wellbores with variable tilt rates, relatively constant tilt rates, wellbores with uniform generally circular cross-sections and wellbores with non-circular cross-sections. 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, relatively hard stringers disposed throughout one or more layers of formation material, and/or concretions (very hard stones) disposed in 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 for determining bit walk characteristics of a rotary drill bit comprising:

applying a set of drilling conditions to the bit including a rate of penetration along a bit rotational axis, at least one characteristic of an earth formation, and at least one characteristic of a wellbore formed by the rotary drill bit;

applying a steer rate to the bit by tilting the bit relative to a fulcrum point located uphole from the bit;

simulating, for a time interval, drilling of the earth formation by the bit under the set of drilling conditions, including calculating a steer force applied to the bit, an associated walk force and an associated walk angle;

calculating a walk rate based at least on the steer force and the walk force;

repeating the simulating successively for a predefined number of time intervals; and

calculating an average walk rate and walk angle for the bit over the simulated time interval.

2. The method of claim 1 wherein applying the characteristics of the wellbore further comprises comparing interior dimensions of the wellbore with exterior dimensions of the rotary drill bit and other downhole tools associated with the rotary drill bit.

3. The method of claim 1 wherein calculating the walk rate further comprises comparing an interior configuration of the wellbore with an exterior configuration of the rotary drill bit and other downhole tools associated with the rotary drill bit.

4. The method as defined in claim 1, further comprising the walk rate, at time t, of the bit calculated by:

Walk Rate=(Steer Rate/Steer Force)×

Walk Force

5. The method of claim 1 further comprising:

determining a bit walk direction of the rotary drill bit by calculating the average bit walk rate over a pre-defined time interval under a pre-defined drilling conditions where at least the magnitude of the given steer rate is not equal to zero; and

determining walk characteristics based on if the average bit walk rate is negative, the bit walks left, and if the average bit walk rate is positive, the bit walks right.

6. A method to find and optimize operational parameters to control bit walk characteristics of a rotary drill bit during drilling of at least one portion of a directional wellbore comprising:

(a) determining a bit path for the at least one portion of the directional wellbore;

(b) determining a desired bit walk rate and walk direction to compensate for the bit path;

(c) determining downhole formation properties at a first location and at a second location ahead of the first location in the at least one portion of the wellbore;

(d) simulating drilling with the rotary drill bit between the first location and the second location, wherein simulating drilling includes predicting a wellbore inside diameter greater than the bit size;

(e) during the simulation applying to the rotary drill bit a steer rate;

(f) calculating a walk rate and walk direction of the rotary drill bit and comparing the calculated walk rate and walk direction with the desired walk rate and walk direction; and

(g) changing at least one set of the bit operational parameters and repeating steps (d) through (f) until the calculated walk rate and walk direction approximately equals the desired walk rate and walk direction.

7. The method of claim 6 further comprising simulating drilling the wellbore with a generally oval shaped configuration.

8. The method of claim 6 further comprising simulating drilling the wellbore with a generally non-symmetrical cross-section.

9. The method of claim 6 further comprising simulating drilling the wellbore with a generally elliptical cross-section.

10. The method of claim 6 further comprising simulating drilling the wellbore with a generally non-circular cross-section.

11. A method for designing a rotary drill bit having an optimum gage pad geometry for a corresponding bit size, the method comprising:

(a) determining one or more formation properties for use in simulating drilling with the bit;

(b) determining one or more drilling conditions for use in simulating drilling with the bit;

(c) simulating drilling using the one or more formation properties and the one or more drilling conditions, and wherein simulating drilling includes predicting a wellbore having at least one segment with a cross-section greater than the bit size;

(d) calculating a walk rate and walk angle based on the simulated drilling;

(e) comparing the calculated walk rate and walk angle with a desired walk rate and desired walk angle;

(f) if the calculated walk rate and calculated walk angle are not approximately equal to the desired walk rate and desired walk angle, changing at least one of the following parameters;

number of gage pads, length of at least one gage pad and wide of at least one gage pad; and

(g) repeating steps (c) through (f) until the calculated walk rate and calculated walk angle approximately equal the desired walk rate and desired walk angle.

12. The method of claim 11 further comprising simulating the wellbore having a generally non-circular cross-section.

13. The method of claim 11 further comprising simulating the wellbore having a generally oval cross-section.

14. The method of claim 11 further comprising simulating the wellbore having a generally elliptical cross-section.

15. The method of claim 11 further comprising simulating the wellbore having a generally non-symmetrical cross-section.

16. A method to prevent an undesired bit walk while forming a directional wellbore with a fixed cutter rotary drill bit and an associated sleeve comprising:

applying a set of drilling conditions to the fixed cutter rotary drill bit including at least bit rotational speed, rate of penetration along a bit rotational axis or bit axial force;

applying at least one characteristic of an earth formation and at least one characteristic of the directional wellbore formed by the fixed cutter rotary drill bit;

applying a steer rate to the fixed cutter rotary drill bit by tilting the bit relative to a fulcrum point used to direct the fixed cutter rotary drill bit to form the directional wellbore;

simulating, for a time interval, drilling the earth formation using the fixed cutter rotary drill bit under the set of drilling conditions, including calculating steer forces applied to the fixed cutter rotary drill bit and associated walk forces and walk angles;

calculating walk rates based at least on the steer forces and the walk forces;

repeating the simulating successively for a predefined number of time intervals;

calculating an average walk rate of the bit over the simulated time interval;

if the simulations indicate undesired bit walk rates, modify the design of the sleeve including at least the length of the sleeve, the width of the sleeve pad and the aggressiveness of the uphole portion of the sleeve to reduce friction forces between the uphole portions of the sleeve and adjacent portions of the wellbore when steering forces are applied to the fixed cutter rotary drill bit; and

repeating the above steps until the resulting simulations indicate that bit walk characteristics of the associated rotary drill bit has been reduced to a satisfactory values.

17. The method of claim 16 further comprising manufacturing the fixed cutter rotary drill bit and the associated sleeve with the design features that corresponded with simulations having a satisfactory bit walk characteristics.

18. A method for determining bit walk characteristics of a rotary drill bit and an associate sleeve comprising:

applying a set of drilling conditions to the bit including at least bit rotational speed, bit axial force, at least one characteristic of an earth formation, and characteristic of a wellbore formed by the rotary drill;

applying a steer rate to the bit by tilting the bit around a fulcrum point located on a sleeve located above the bit gage, wherein the fulcrum point is defined as a contact between exterior portion of the sleeve and adjacent portion of wellbore;

simulating, for a time interval, drilling of the earth formation by the bit under the set of drilling conditions, including calculating a steer force applied to the bit and an associated walk force;

calculating a walk rate based at least on the steer force and the walk force;

repeating the simulating successively for a predefined number of time intervals; and

calculating average walk characteristics of the bit over the simulated time interval.

19. A method for determining bit walk characteristic of a rotary drill bit while forming a directional wellbore in a soft downhole formation comprising:

applying a set of drilling conditions to the bit and associated downhole tools including at least rate of penetration along a bit rotational axis and at least one characteristic of the soft downhole formation;

simulating, for a time interval, drilling of the soft downhole formation by the bit and associated downhole tools under the set of drilling conditions, including calculating forces applied to the bit and the associated downhole tools;

calculating an average walk force and associated walk direction based at least on respective walk forces acting on the two or more components of the bit and the associated downhole tools;

repeating the simulating for a predefined number of time intervals; and

calculating walk characteristics of the bit and the associated downhole tools using the average walk force over the simulated time interval.

20. The method of claim 19 further comprising simulating drilling of the soft downhole formation using a point-the-bit rotary steerable system with a sleeve extending from an uphole portion of the rotary drill bit.

21. The method of claim 19 wherein calculating the walk characteristics further comprises:

determining respective three dimensional locations of all cutting edges of all cutting elements and all gage portions in a hole coordinate system;

determining respective interactions of all cutting edges of the cutting elements and gage portions with the soft downhole formation;

calculating a cutting depth for each cutting element;

calculating respective three dimensional forces of the cutting elements and projecting the forces into a hole coordinate system;

summing all of the forces projected in the hole coordinate system;

projecting the summed forces into a tilting plane; and

calculating a steer force in the vertical tilting plane and perpendicular to bit rotational axis.

22. The method of claim 19 further comprising:

calculating forces acting on an uphole portion of the sleeve; and

modifying the design of exterior portions of the sleeve to reduce forces acting thereon to provide desired bit walk characteristics for the bit and the associated downhole tool.

23. The method of claim 19 further comprising modifying aggressiveness of at least one gage pad disposed on exterior portions of the sleeve adjacent to an uphole end of the sleeve.

24. A method for determining bit walk rate of a rotary drill bit having long gage pads comprising:

applying a set of drilling conditions to the bit including at least bit rotational speed, hole size and rate of penetration along a bit rotational axis and at least one characteristic of an earth formation;

simulating, for a time interval, drilling of the earth formation by the bit under the set of drilling conditions, including calculating forces applied to the bit including the long gage pads;

repeating the simulating successively for a predefined number of time intervals;

calculating walk characteristics acting on the bit including the long gage pads;

modifying the design of the long gage pads;

repeating the above simulating and modifying the design of the long gage pad until average walk characteristics correspond with desired walk characteristics for the bit; and

calculating average walk rate characteristics of the bit.

25. A method to find and optimize design parameters to control bit walk characteristics of a rotary drill bit during drilling of at least one portion of a directional wellbore comprising:

(a) determining a bit path to form the at least one portion of the directional wellbore;

(b) determining downhole formation properties at a first location and a second location downhole from the first location in the at least one portion of the directional wellbore;

(c) simulating drilling the bit path with the rotary drill bit between the first location and the second location using a point-the-bit directional drilling system;

(d) calculating walk characteristics of the rotary drill bit;

(e) simulating drilling the bit path with the rotary drill bit between the first location and the second location using a push-the-bit directional drilling system;

(f) calculating walk characteristics of the rotary drill bit;

(g) comparing the walk characteristics of the rotary drill bit when using the point-the-bit directional drilling system and when using the push-the-bit directional drilling system;

(h) changing at least one of the bit design parameters and repeating steps (b) through (g) until the calculated walk characteristics approximately equal desired walk characteristics; and

(i) selecting the push-the-bit directional drilling system or the point-the-bit directional drilling system and design parameters of the rotary drill bit for use in forming the at least one portion of the directional wellbore.

26. A rotary drill bit with a desired bit walk rate prepared by a process comprising:

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

(b) simulating drilling at least one portion of a wellbore having a wellbore diameter greater than the bit diameter, using the one or more drilling conditions;

(c) calculating an average bit walk rate;

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

(e) if the calculated bit walk rate does not approximately equal the desired walk rate, performing the following steps;

(f) dividing the bit body into at least an inner zone, a shoulder zone, an active gage zone and a passive gage zone;

(g) calculating the walk rate of each zone;

(h) calculating the walk rate of a first combined zone including the inner zone and the shoulder zone;

(i) calculating the walk rate of a second combined zone including the active gage zone and the passive gage zone;

(j) identifying the zone which has the maximal magnitude of walk rate and the zone which has the minimal magnitude of walk rate;

(h) modifying one or more structures within the zone which has the maximal magnitude of walk rate or the zone which has the minimal magnitude of the walk rate;

(k) repeating steps (b) through (j) until the calculated bit walk rate approximately equals the desired bit walk rate; and

(l) manufacturing the long gage rotary drill bit having the desired bit walk rate.

27. The rotary drill bit of claim 27, further comprising the rotary drill bit prepared by a process wherein calculating an average bit walk rate further comprises:

applying a set of drilling conditions to the bit including at least bit rotational speed, hole size and rate of penetration along a bit rotational axis and at least one characteristic of an earth formation;

applying a steer rate to the bit, wherein applying the steer rate includes tilting the bit around a fulcrum point located at a top section of the bit gage;

simulating, for a time interval, drilling of the earth formation by the bit under the set of drilling conditions, including calculating a steer moment applied to the bit and an associated walk moment;

calculating a walk rate based on the bit steer rate, the steer moment, and the walk moment;

repeating simulating drilling the earth formation for another time interval, and recalculating the steer moment, the walk moment and walk rate;

repeating the simulating successively for a predefined number of time intervals; and

calculating an average walk rate of the bit using an average steer moment and an average walk moment over the simulated time interval.

28. A rotary drill bit having a gage and corresponding bit size, prepared by a process comprising:

(a) determining one or more formation properties for use in simulating drilling with the bit;

(b) determining one or more drilling conditions for use in simulating drilling with the bit;

(c) simulating drilling using the one or more formation properties and the one or more drilling conditions, and wherein simulating drilling includes predicting a wellbore diameter greater than the bit size;

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

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

(f) if the calculated walk rate is not approximately equal to the desired walk rate, changing a bit geometry or changing a geometric parameter of the gage;

(g) repeating steps (c) through (f) until the calculated walk rate approximately equals the desired walk rate; and

(h) manufacturing the rotary drill bit having the desired bit walk rate.