Methods and system for designing and/or selecting drilling equipment with desired drill bit steerability

• US 20070029113A1
• Filed: 08/07/2006
• Published: 02/08/2007
• 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
• Granted Patent: US 7,729,895 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 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. Values of bit steerability and controllability calculated 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 steerability of a rotary drill bit comprising:

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

(b) applying a steer rate to the bit;

(c) simulating for a time interval drilling the earth formation by the bit under the set of drilling conditions including calculating a steer force applied to the bit;

(d) simulating drilling the earth formation for another time interval and recalculating the steer force;

(e) repeating simulating drilling the earth formation successively for a predefined number of time intervals;

(f) calculating an average steer force applied to the bit over the simulated time intervals;

(g) saving the applied steer rate and the calculated average steer force;

(h) repeating, within a predefined range of steer rates, steps (b) to (g) by incrementally increasing the bit steer rate; and

(i) analyzing mathematically steer forces as a function of steer rates.

2. The method of claim 1 wherein applying the steer rate further comprises applying the steer rate in a vertical plane passing through the bit axis.

3. The method of claim 1 wherein calculating the steer force further comprises:

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

determining respective interactions of all cutting edges of all cutters and all gages with the bottom hole of the formation;

calculating the cutting depth for each cutting edge and a cutting area for each cutting element;

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

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

projecting the summed forces into the vertical tilt plane; and

calculating the steer force by further projecting the in-plane force to a line perpendicular to bit axis;

4. The method of claim 1, wherein analyzing mathematically the steer force further comprises:

fitting the data points of steer force and steer rate to express the bit steer force as a linear function of bit steer rate; and

calculating bit steerability as a slope of the linear function.

5. The method as defined in claim 1, wherein analyzing mathematically the steer force further comprises:

fitting the data points of steer force and steer rate to express the bit steer force as a non-linear function of bit steer rate; and

calculating bit steerability as a first derivative of the nonlinear function.

6. A method for determining steerability of a rotary drill bit comprising:

(a) selecting a set of drilling conditions for the bit including at least bit rotational speed, rate of penetration along a bit axis and at least one characteristics of an earth formation;

(b) selecting a first steer rate for the bit;

(c) simulating drilling the earth formation for a time interval using the bit with the set of drilling conditions and calculating a steer moment required for the bit to achieve the first steer rate;

(d) simulating drilling the earth formation for another time interval and recalculating the steer moment;

(e) repeating the simulating drilling the earth formation successively for a predefined number of time intervals; and

(f) calculating an average steer moment over the simulated time interval;

(g) saving the applied steer rate and the calculated steer moment;

(h) repeating, within a predefined range of steer rates, steps (b) to (g) by incrementally increasing bit steer rate; and

(i) analyzing mathematically steer moments as a function of steer rates.

7. The method of claim 6 comprising calculating an optimum negative taper angle for a gage portion of the rotary drill bit.

8. The method of claim 6, further comprising calculating a steerability difficulty index for the rotary drill bit.

9. The method of claim 6 wherein calculating the steer moment further comprises:

determining respective three dimensional locations of all cutting edges of all cutters and all gage blades in hole coordinate system;

determining the interaction of all cutting edges of the cutter and gage blades with the bottom hole of the formation;

calculating the cutting depth of each cutting edge and cutting area of each cutting element;

calculating the three dimensional forces of the cutting elements;

calculating the three dimensional moments of the cutting elements around a predefined point on bit axis;

projecting the three moments into the hole coordinate system;

summing all the cutting element moments projected in the hole coordinate system; and

projecting the summed steer moments into the plane perpendicular to the vertical plane to get the steer moment of the bit;

10. The method as defined in claim 6, wherein analyzing mathematically the steer moment comprises:

fitting the data points of steer moment and steer rate linearly along a line to express the steer moment as a linear function of steer rate; and

calculating bit steerability as a function of a slope of the line.

11. The method as defined in claim 6, wherein analyzing mathematically the steer moment comprises:

fitting the data points of steer moment and steer rate to express the bit steer moment as a non-linear function of bit steer rate; and

calculating bit steerability as a first derivative of the nonlinear function.

12. A method for determining a bit steering difficulty index, under a given set of drilling conditions, for a fixed cutter drill bit having a bit axis comprising:

dividing the bit body into zones selected from the group consisting of an inner zone, shoulder zone, gage cutter zone, active gage zone and passive gage zone;

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

applying a steer rate in a vertical plane passing through bit axis;

simulating for a time interval drilling of the earth formation by the bit under the given drilling conditions;

calculating a steer force for each zone around a pre-defined point on bit axis; and

calculating a steer difficulty index of each zone by dividing the steer force of each zone with the steer rate.

13. The method of claim 12 further comprising summing all of the steer difficulty indexes for all zones to obtain the bit steer difficulty index.

14. The method of claim 12 further comprising:

comparing the steer difficulty indexes of each selected zone with the steer difficulty indexes of the other selected zones;

identifying at least one zone with an unsatisfactory steer difficulty indexes; and

modifying design features of each zone having an unsatisfactory steer difficulty indexes and repeating the calculating of steer difficulty indexes until the steer difficulty indexes for each zone is satisfactory.

15. A method for determining a bit steering difficulty index, under a given set of drilling conditions, for a fixed cutter drill bit having a bit axis comprising:

dividing the bit body into zones selected from the group consisting of an inner zone, shoulder zone, gage cutter zone, active gage zone and passive gage zone;

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

applying a steer rate in a vertical plane passing through bit axis;

simulating for a time interval drilling of the earth formation by the bit under the given drilling conditions;

calculating a steer moment for each zone around a pre-defined point on bit axis; and

calculating a steer difficulty index of each zone by dividing the steer moment of each zone with the steer rate.

16. The method of claim 15 further comprising summing all of the steer difficulty indexes for all zones to obtain the bit steer difficulty index.

17. The method of claim 15 further comprising:

comparing the steer difficulty indexes of each selected zone with the steer difficulty indexes of the other selected zones;

identifying at least one zone with an unsatisfactory steer difficulty indexes; and

modifying design features of each zone having an unsatisfactory steer difficulty indexes and repeating the calculating of steer difficulty indexes until the steer difficulty indexes for each zone is satisfactory.

18. A method to design a rotary drill bit with a desired bit steering difficulty index 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 a bit steering difficulty index;

(d) comparing the calculated the bit steering difficulty index to desired the bit steer difficulty index;

(e) if the calculated the bit steering difficulty index does not approximately equal the desired the bit steering difficulty index, performing the following steps;

(f) dividing the bit body into zones selected from the group consisting of inner zone, shoulder zone, gage cutter zone, active gage zone and passive gage zone;

(g) calculating the bit steering difficulty index of each zone;

(h) adding the bit steering difficulty index of inner zone and shoulder zone to get a face cutter steering difficulty index;

(i) adding the steering difficulty index of the active gage zone and the passive gage zone to get a gage steer difficulty index;

(j) comparing the steering difficulty index of each zone;

(k) modifying the structure within a selected zone beginning with the zone which has the largest steering difficulty index; and

(l) repeating steps (b) through (k) until the calculated bit steering difficulty index approximately equals the desired bit steering difficulty index.

19. The method of claim 18, wherein the modifying the structure within the inner zone including at least the cone angle, the number of blades, the number of cutters, the location of cutters, the size of cutters and the back rake and side rake angles of each cutter.

20. The method of claim 18, wherein the modifying of the structure within the shoulder zone including at least the number of blades, the number of cutters, the location of cutters, the size of cutters and the back rake and side rake angles of each cutter.

21. The method of claim 18, wherein the modifying of the structure within the gage cutter zone including at least the number of gage cutters, the location of gage cutters, the size of cutters and the back rake and side rake angles of each gage cutter.

22. The method of claim 18, wherein the modifying of the structure within the active gage zone including at least the length of the active gage, the number of blades, the width of each blade, the spiral angle of each blade, the diameter of the active gage and the aggressiveness of the active gage.

23. The method of claim 18, wherein the modifying of the structure within the passive gage zone including at least the length of the passive gage, the number of blades, the width of each blade, the spiral angle of each blade, the diameter of the passive gage, the number of steps of passive gage and the taper angle of the passive gage.

24. The method of claim 18 further comprising designing the rotary drill bit for use with a directional drilling system selected from the group consisting of a push-the-bit steerable drilling system or a point-the-bit steerable drilling system.

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

selecting a desired bit path deviation and a desired bit steer rate for drilling the at least one portion of the wellbore;

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

selecting a first set of bit operational parameters from the group consisting of rate of penetration, revolutions per minute, weight on bit and the desired bit steer rate;

simulating drilling the at least one portion of the wellbore with the rotary drill bit using the first set of bit operational parameters;

calculating an associated bit steer force (F_sbit), using a bit/formation interaction model based on side forces required to tilt the rotary drill bit under the first set of bit operational parameters;

calculating, using a BHA mechanics model, the available side force (F_sbha), provided by the bottom hole assembly associated with the rotary drill bit;

comparing F_sbit with F_sbha;

if F_sbha is smaller than F_sbit, modifying the bottom hole assembly to increase F_sbha or modifying the first set of bit operational parameters to decrease F_sbit, or modifying both the bottom hole assembly and the first set of bit operational parameters to increase F_sbha and decrease F_sbit; and

continue simulating drilling with the modified set of bit operational parameters and/or modified bottom hole assembly.

26. The method of claim 25 further comprising determining optimum bit operational parameters to control steerability of a fixed cutter rotary drill bit.

27. The method of claim 25 further comprising repeating simulated drilling of additional portions of the wellbore and comparing F_sbit with F_sbha to determine optimum bit operational parameters to control steerability of the rotary drill bit in each portion of the wellbore.

28. The method of claim 25 further comprising calculating a respective tilt rate for various portions of the wellbore using the general formula:

Tilt Rate=DLS×

ROP/100 (degrees/hour)

where DLS=change in degrees from vertical per 100 feet of wellbore length; and

ROP=rate of penetration during forming of the wellbore in feet/hour.

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

(a) selecting a first rotary drill bit with a prior history of satisfactorily drilling wellbores with the desired trajectory for use in simulating drilling of the wellbore;

(b) determining formation properties associated with the wellbore;

(c) calculating steerability of the first rotary drill bit from a three dimensional bit/rock interaction model under a set of bit operational parameters;

(d) selecting a second rotary drill bit with a desired bit steer rate under the set of bit operational parameters;

(e) calculating steerability of the second rotary drill bit using the set of bit operational parameters;

(f) comparing steerability of the first rotary drill bit with steerability of the second rotary drill bit; and

(g) if steerability of the second rotary drill bit is not better than steerability of the first rotary drill bit, selecting another rotary drill bit and repeating steps (d) through (g) until a final rotary drill bit is found with steerability better than steerability of the first rotary drill bit.

30. The method of claim 29 further comprising:

monitoring the trajectory of the final rotary drill bit during simulated drilling of the wellbore; and

if the simulated trajectory of the final rotary drill bit does not correspond approximately with the desired trajectory, modifying at least one portion of the set of bit operational parameters until the simulated trajectory corresponds approximately with the desired trajectory.

31. The method of claim 29 further comprising selecting a fixed cutter rotary drill bit to drill the wellbore.

32. The method of claim 29 further comprising selecting at least one component of a bottom hole assembly for use with the fixed cutter rotary drill bit.

33. A method to design a rotary drill bit with desired steerability comprising:

(a) choosing an existing rotary drill bit design (design A) which was previously used in a steerable drilling system;

(b) simulating applying tilting motion, axial penetration and rotation forces to design A for selected formation properties of transition layer strength and inclination angle;

(c) calculating steerability for design A;

(d) designing a new rotary drill bit (design B) to be more steerable than design A under the same set of drilling conditions;

(e) simulating applying the same tilting motion, axial penetration and rotation forces to design B for the selected formation properties of transition layer strength and inclination angle;

(f) calculating steerability for design B;

(g) if design B has a value of steerability lower than the value of steerability for design A, modifying design B by adjusting at least one feature associated inner and outer cutting structures of design B; and

(h) repeating steps (e) through (g) until the calculated steerability of design B is greater than the calculated steerability of design A;

34. The method of claim 33 wherein modifying design B comprises adjusting at least one feature selected from the group consisting of bit face profile, cutter size, cutter location, cutter orientation (back rake and side rake), number of blades and number of cutters, or change geometric parameters of an associated active or passive gage such as gage length, gage radius, gage taper angle and gage blade spiral angle.

35. A rotary drill bit with desired steerability 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 radially outward from the shoulder 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 calculations of bit of steerability of the rotary drill bit with various ratios of inner cutters and shoulder cutters.

36. The drill bit of claim 35 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.

37. The drill bit of claim 35 further comprising a passive gage portion having a negative taper angle optimized for use in forming a directional wellbore.

38. The drill bit of claim 35 further comprising the bit face profile providing means for optimizing use of the drill bit with a drilling system selected from the group consisting of a push-the-bit steerable drilling system and a point-the-bit steerable drilling system.

39. A method to find and optimize parameters associated with a bottom hole assembly to control steerability of a rotary drill bit during drilling at least one portion of a directional wellbore comprising:

selecting a desired bit path deviation and a desired bit steer rate for drilling the at least one portion of the wellbore;

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

selecting a first set of bit operational parameters from the group consisting of rate of penetration, revolutions per minute, weight on bit and the desired bit steer rate;

simulating drilling the at least one portion of the wellbore with the rotary drill bit using the first set of bit operational parameters;

calculating an associated bit steer force (F_sbit), using a bit/formation interaction model based on steer forces required to steer the rotary drill bit under the first set of bit operational parameters;

calculating, using a BHA mechanics model, the available side force (F_sbha), provided by the bottom hole assembly associated with the rotary drill bit;

comparing F_sbit with F_sbha;

if F_sbha is smaller than F_sbit, modifying the bottom hole assembly to increase F_sbha or modifying the first set of bit operational parameters to decrease F_sbit, or modifying both the bottom hole assembly and the first set of bit operational parameters to increase F_sbha and decrease F_sbit; and

continue simulating drilling with the modified set of bit operational parameters and/or modified bottom hole assembly.

40. The bottom hole assembly of claim 39 further comprising simulating drilling another portion of the wellbore.

41. The bottom hole assembly of claim 39 further comprising determining optimum bit operational parameters to control steerability of a fixed cutter rotary drill bit.

42. The bottom hole assembly of claim 39 further comprising repeating simulated drilling of additional portions of the wellbore and comparing F_sbit with F_sbha to determine optimum bit operational parameters to control steerability of the rotary drill bit in each portion of the wellbore.

43. A fixed cutter rotary drill bit having steerability characteristics optimized to drill a directional wellbore comprising:

a bit body having a plurality of cutter disposed thereon;

the cutters operable to engage adjacent portions of a downhole formation to form the directional wellbore;

at least one passive gage disposed on the bit body;

the at least one passive gage having a negative taper angle; and

the negative taper angle selected to prevent undesired contact between the at least one passive gage and adjacent portions of a straight hole segment of the wellbore.

44. The drill bit of claim 43 further comprising blades and associated cutter optimized for drilling the directional wellbore.

45. The drill bit of claim 43 further comprising an active gage disposed at a location on the bit body to optimize drilling the directional wellbore.

46. The drill bit of claim 43 further comprising means for reducing the steering difficulty index of the rotary drill bit.

47. A rotary drill bit with desired steerability comprising:

a bit body having a plurality of blades extending therefrom;

each blade having a plurality of cutters disposed thereon; and

the location, number, size and type of cutter disposed on each blade providing means for optimizing a steering difficulty index of the rotary drill.

48. The drill bit of claim 47 further comprising at least one feature, selected from the group consisting of bit face profile, cutter size, cutter location, cutter orientation(back rake and side rake), number of blades and number of cutters, geometric parameters of an associated active or passive gage including gage length, gage taper angle and blade spiral angle, providing means for optimizing the steering difficulty index of the rotary drill bit.