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

• US 7,827,014 B2
• Filed: 08/07/2006
• Issued: 11/02/2010
• 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:
  US11/462,929
• Publication Number:
  US 20070032958A1
• Time in Patent Office: 1,548 Days
• Field of Search: 703/10, 709/2, 367/82
• US Class Current: 703/10
• 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 simulating drilling at least one portion of a wellbore using a rotary drill bit comprising:

selecting a drilling mode from the group consisting of straight, kick off or equilibrium corresponding with the one portion of the wellbore;

inputting drilling equipment data including bit rotational speed, axial bit penetration rate and lateral bit penetration rate;

inputting wellbore data and formation data corresponding with the at least one portion of the wellbore;

applying a steer rate to the rotary drill bit as part of the simulation; and

simulating drilling the one portion of the wellbore using the drilling equipment data for the proposed set of drilling equipment, the wellbore data, and the formation data.

2. The method of claim 1 further comprising selecting at least a portion of the formation data from the group consisting of a first layer rock strength, a second layer rock strength, an up angle for one layer or a down angle for one layer.

3. The method of claim 1 further comprising:

modifying at least one feature of the proposed set of drilling equipment; and

repeating the simulation of drilling the at least one portion of the wellbore.

4. The method of claim 1 further comprising designing a set of drilling equipment for use with a push-the-bit directional drilling system.

5. The method of claim 1 further comprising designing a set of drilling equipment for use with a point-the-bit directional drilling system.

6. The method of claim 1 further comprising selecting a set of drilling equipment from existing drilling equipment designs for use with a push-the-bit directional drilling system.

7. The method of claim 1 further comprising selecting a set of drilling equipment from existing drilling equipment designs for use with a point-the-bit directional drilling system.

8. The method of claim 1 further comprising calculating 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.

9. The method of claim 1 further comprising calculating a walk rate of the rotary drill bit based at least in part on side forces and walk forces calculated as a function of the steer rate applied to the rotary drill bit.

10. 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 bit design data;

inputting formation data;

inputting downhole drilling conditions for straight hole portion drilling including bit rotational speed, rate of penetration and weight on bit;

simulating drilling the straight hole portion by selecting straight drilling as a drilling mode and using the bit design data and the downhole drilling conditions for the straight hole portion;

inputting downhole drilling conditions for kick off portion drilling including bit rotational speed, rate of penetration, weight on bit, tilt rate and bend length;

simulating drilling the kick off portion by selecting kick off drilling as a drilling mode and using the bit design data and downhole drilling conditions for the kick off portion;

inputting downhole drilling conditions for equilibrium portion drilling including bit rotational speed, rate of penetration, and weight on bit, tilt rate and bend length; and

simulating drilling the equilibrium portion by selecting equilibrium drilling as a drilling mode and using the bit design data and downhole drilling conditions for the equilibrium portion.

11. The method of claim 10 wherein simulating drilling further comprising:

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

projecting, for each drilling mode, the calculated forces into a bit coordinate system which rotates with the bit; and

projecting, for each drilling mode, the calculated forces into a hole coordinate system which is fixed with the formation.

12. The method of claim 10, 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.

13. The method in claim 10, further comprising calculating, for each drilling mode, a bit walk force, a bit walk moment and a bit walk rate due to the formation layers.

14. The method in claim 10, further comprising calculating, for each drilling mode, a bit steering force and a bit steering moment due to the formation layers and a bit steerability index.

15. The method of claim 10 further comprising:

modifying the bit design data; and

repeating the simulation of drilling at least one portion of the wellbore using the corresponding drilling mode.

16. The method of claim 10 further comprising:

changing at least one downhole drilling condition; and

repeating the simulation of drilling the at least one portion of the wellbore using the corresponding drilling mode.

17. The method of claim 10 further comprising designing a rotary drill bit for use with a push-the-bit directional drilling system based at least in part on the results of the simulations.

18. The method of claim 10 further comprising designing a rotary drill bit for use with a point-the-bit directional drilling system based at least in part on the results of the simulations.

19. The method of claim 10 further comprising selecting a rotary drill bit from existing drilling equipment designs for use with a push-the-bit directional drilling system based at least in part on the results of the simulations.

20. The method of claim 10 further comprising selecting a rotary drill bit from existing drilling equipment designs for use with a point-the-bit directional drilling system based at least in part on the results of the simulations.

21. A method of simulating drilling portions of a wellbore comprising:

selecting a first set of drilling equipment for use in simulating drilling at least one portion of the wellbore;

inputting design parameters for the first set of drilling equipment;

selecting operating parameters for the drilling equipment from the group consisting at least of rate of penetration weight on bit, bit rotation speed and a desired bit tilt rate;

inputting formation data at a first location in the at least one portion of the wellbore;

inputting formation data at a second location in the at least one portion of the wellbore;

simulating forming a bottom hole of the wellbore by rotating the drilling equipment one full revolution without any penetration of the adjacent formation;

calculating spherical coordinates for the simulated bottom hole in a hole coordinate system;

calculating spherical coordinates in the same hole coordinate for a plurality of points of interest on the drilling equipment at a specified time; and

simulating drilling the bottom hole, by calculating a three dimensional interaction of all points of interest on the drilling equipment with one or more adjacent portions of the bottom hole in the same spherical coordinate system.

22. The method of claim 21 further comprising:

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

calculating, using a BHA mechanics model, available side force (F_sbha) provided by a bottom hole assembly associated with the first set of drilling equipment;

comparing F_sbha with F_sbit;

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

continue simulating drilling with the modified operational parameters and/or modified drilling equipment to determine if F_sbha is equal to or greater than F_sbit.

23. The method of claim 21 further comprising selecting parameters for each simulation from the group consisting of total simulation time, step time, mesh size of the drilling equipment in spherical coordinates and mesh size of the bottom hole of the wellbore in spherical coordinates.

24. The method of claim 21 further comprising:

calculating the spherical coordinates, in the hole coordinate system, for all points of the bottom hole, φ

_H, θ

_H and P_H;

calculating spherical coordinates of φ

_C, θ

_C and P_C, in the same hole coordinate system, at a specific time, based on bit operating data, for a plurality of interest points on an associated rotary drill bit;

calculating an interpolated radius coordinate, ρ

_CH of the spherical coordinates in the same hole coordinate system, for the plurality of interest points on the drilling equipment, by using two dimensional data interpolation technique and the bottom hole spherical coordinates, φ

_H, θ

_H and ρ

_H, and ρ

_CH=f(φ

_H, θ

_H, ρ

_H φ

_C, θ

_C);

calculating the cutting depth of each interest point on the drilling equipment by

Δ

=ρ

_C−

ρ

_CH if ρ

_C>

ρ

_CH

Δ

=0;

if ρ

_C<

=ρ

_CH

updating the bottom hole by replacing ρ

CH with ρ

C if ρ

_C>

ρ

_CH; and

repeating the above steps for all other interest points on the drilling equipment.

25. A method of simulating drilling performance of equipment operable to form a wellbore with a desired trajectory comprising:

(a) selecting a first set of drilling equipment with a prior history of satisfactorily drilling wellbores with a set of bit operational parameters and a bit tilt rate corresponding with the desired trajectory;

(b) determining formation data associated with the wellbore;

(c) selecting a drilling mode from the group consisting of straight hole drilling, kick-off drilling and equilibrium drilling corresponding with the wellbore;

(d) calculating steerability of the first set of drilling equipment based on a three dimensional simulation of interactions between the drilling equipment and adjacent portions of the wellbore under the set of bit operational parameters and the set of formation data;

(e) selecting another set of drilling equipment with the bit tilt rate under the set of bit operational parameters;

(f) calculating steerability of the second set of drilling equipment using the set of bit operational parameters and the set of formation data;

(g) comparing steerability of the first set of drilling equipment with steerability of the second set of drilling equipment; and

(h) if steerability of the second set of drilling equipment is not better than steerability of the first set of drilling equipment, selecting another set of drilling equipment and repeating steps (c) through (g) until a final set of drilling equipment is found with steerability better than steerability of the first set of drilling equipment.

26. The method of claim 25 further comprising:

simulating forming the wellbore using the final set of drilling equipment the set of formation data and the set of bit operational parameters;

comparing the simulated trajectory of the wellbore with the desired trajectory of the wellbore; and

modifying at least one portion of the set of bit operational parameters until the simulated trajectory corresponds approximately with the desired trajectory.

27. A computer system for simulating drilling a wellbore through a subterranean formation comprising:

at least one processing resource operable to communicate with at least one memory resource and at least one display;

computer instructions stored in the at least one memory resource for use by the at least one processing resource to simulate drilling at least one portion of the wellbore;

the display operable to show the results of a simulation performed by the computer system;

the computer instructions operable to convert a bottom hole of the wellbore into a spherical coordinate system;

the computer instructions operable to convert design parameters of the drilling equipment into a spherical coordinate system;

the computer instructions operable to simulate applying bit tilting motion, axial penetration and rotation forces to the drilling equipment; and

the computer instructions operable to simulate in three dimensions using the spherical coordinate system interactions between a rotary drill bit associated with the drilling equipment and a three dimensional simulation of the bottom hole of the wellbore.

28. A system for simulating drilling a wellbore comprising:

at least one processing resource and at least one memory resource operably coupled with each other;

a software application stored on the at least one memory resource;

at least one display operable to show results of a simulation performed by the processing resources using the software application;

the software application operable to simulate forces acting on a first set of drilling equipment including forces associated with tilting of a rotary drill bit during formation of a directional wellbore;

the software application operable to calculate side forces acting upon the drilling equipment based on the simulation; and

the software application operable to calculate a bit walk rate for a rotary drill bit associated with the first set of drilling equipment.

29. The system of claim 28 further comprising:

the software application operable to calculate a first position of a mesh segment of the rotary drill bit based upon simulated penetration of the bottom hole of the wellbore by the rotary drill bit; and

the software application operable to calculate a second position for the mesh segment of the rotary drill bit due to rotation of the rotary drill bit about the longitudinal axis of the rotary drill bit.

30. The system of claim 28 further comprising:

the software application operable to calculate the position of a mesh segment of the rotary drill bit in a first formation layer;

the software application operable to calculate the position of the mesh segment of the rotary drill bit in a second formation layer; and

the software application operable to save layer information, cutting depth and cutting area in a three dimensional matrix at each step of the simulation process.

31. The system of claim 28 further comprising:

the software application operable to calculate respective forces applied to the drill bit along an X, Y and Z axes with the Z axis extending generally parallel with a longitudinal axis of the drill bit; and

the software application operable to calculate rotational forces applied to the drill bit along the X, Y and Z axes.

32. The system of claim 28 further comprising the software application operable to calculate torque applied to the rotary drill bit and changes in torque applied to the rotary drill bit by the drilling equipment.

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

processing resources communicating with an input device, memory resources and at least one visual display;

the memory resources operable to store software, computer programs, algorithms, drilling equipment design data and downhole drilling conditions;

means for selecting downhole drilling conditions and drilling equipment design data for use in simulating drilling at least one portion of a directional wellbore;

the processing resources operable to;

(a) simulate drilling the at least one portion of a wellbore using the selected downhole drilling conditions and drilling equipment design data;

(b) calculate a bit steerability; and

(c) compare the calculated bit steerability to a desired bit steerability;

if the calculated steerability does not approximately equal the desired steerability, means for modifying at least one bit geometry of the rotary drill bit selected from the group consisting of bit face profile, cutter location, cutter orientation, cutter density, gage length and gage diameter; and

the processing resources operable to repeat steps (a) through (c) until the calculated steerability approximately equals the desired steerability.

34. The system of claim 33 further comprising:

means for checking the calculation of the bit steerability by changing at least one of the drilling conditions; and

the processing resources operable to repeat steps (a) to (c).