Methods and systems for modeling, designing, and conducting drilling operations that consider vibrations

• US 8,214,188 B2
• Filed: 09/30/2009
• Issued: 07/03/2012
• Est. Priority Date: 11/21/2008
• Status: Active Grant

• Current Assignee: Exxonmobil Upstream Research Company (Exxon Mobil Corporation)
• Original Assignee: Exxonmobil Upstream Research Company (Exxon Mobil Corporation)
• Inventors: Bailey, Jeffrey R., Wang, Lei, Sundararaman, Shankar, Ertas, Mehmet Deniz, Gupta, Vishwas, Biediger, Erika A. O.
• Primary Examiner(s): Craig, Dwin M
• Application Number:
  US13/121,633
• Publication Number:
  US 20110214878A1
• Time in Patent Office: 1,007 Days
• Field of Search: 703/10, 703/7, 702/6
• US Class Current: 703/10
• CPC Class Codes: E21B 7/00 Special methods or apparatus for drilling

Abstract

A method and apparatus associated with the production of hydrocarbons is disclosed. The method, which relates to modeling and operation of drilling equipment, includes constructing one or more surrogates for at least a portion of a bottom hole assembly (BHA) and calculating performance results from each of the one or more surrogates. The calculated results of the modeling may include one or more vibration performance indices that characterize the BHA vibration performance of the surrogates for operating parameters and boundary conditions, which may be substantially the same as conditions to be used, being used, or previously used in drilling operations. The selected BHA surrogate may then be utilized in a well construction operation and thus associated with the production of hydrocarbons.

Claims

1. A method of modeling drilling equipment to represent vibrational performance of the drilling equipment, the method comprising:

a) constructing at least one surrogate representing at least a portion of a bottom hole assembly;

b) associating at least two virtual sensors with each of the at least one surrogates, wherein the at least two sensors are spaced longitudinally from each other along each bottom hole assembly;

c) utilizing at least one frequency-domain model to calculate at least one state of the at least two virtual sensors during one or more simulated drilling operations for each of the at least one surrogates;

d) calculating a transmissibility index between the at least two virtual sensors for each of the at least one surrogates, wherein the transmissibility index is based at least in part on at least one of the calculated states; and

e) using the calculated transmissibility index for each of the at least one surrogates to determine the transmissibility of vibrations within the bottom hole assembly.

2. The method of claim 1 wherein the calculated at least one state comprises at least one of displacement, tilt angle, bending moment, and shear force.

3. The method of claim 1 wherein the calculated transmissibility index is a ratio between calculated accelerations of the at least two virtual sensors derived from one or more of the calculated states.

4. The method of claim 1 wherein a transmissibility index greater than 1 predicts that vibrations would increase between a first virtual sensor and a second virtual sensor.

5. The method of claim 1 wherein a transmissibility index less than 1 predicts that vibrations would decrease between a first virtual sensor and a second virtual sensor.

6. The method of claim 1 wherein at least one of the virtual sensors is associated with a bit of the at least one bottom hole assembly surrogate, wherein a transmissibility index is calculated for a plurality of points along the surrogate, and wherein the usage of the calculated transmissibility indices is a plot wherein peaks of the transmissibility plot indicate locations of local peak vibration in the surrogate bottom hole assembly.

7. The method of claim 1 further comprising:

f) drilling at least a portion of a well with a bottom hole assembly at least substantially embodying a surrogate used to calculate a transmissibility index while measuring acceleration at least at two sensors disposed along the embodied bottom hole assembly;

g) calculating a measured transmissibility index using the measured accelerations; and

h) comparing the measured transmissibility index with the transmissibility index of the surrogate.

8. The method of claim 7 further comprising updating the at least one surrogate to represent a different bottom hole assembly configuration and repeating steps (b)-(e).

9. The method of claim 7 further comprising modifying drilling operations on the well based at least in part on the measured transmissibility index and the surrogate transmissibility index.

10. The method of claim 7 further comprising updating one or more of the at least one surrogate, the at least two virtual sensors, the at least one frequency-domain model, and the transmissibility index calculations based at least in part on the comparison of the measured transmissibility index and the transmissibility index of the at least one surrogate.

11. A method of drilling a well for use in the production of hydrocarbons, the method comprising:

a) constructing at least one surrogate representing at least a portion of a bottom hole assembly, wherein the at least one surrogate includes at least two virtual sensors;

b) calculating a transmissibility index between the at least two virtual sensors for each of the at least one surrogates;

c) selecting an optimized bottom hole assembly configuration for a drilling operation based at least in part on the calculated transmissibility index; and

d) drilling a well with drilling equipment incorporating a bottom hole assembly at least substantially embodying the selected bottom hole assembly configuration.

12. The method of claim 11 wherein drilling the well is conducted according to a drilling plan developed based at least in part on the calculated transmissibility index.

13. The method of claim 11 wherein selecting an optimized bottom hole assembly configuration comprises selecting different bottom hole assembly configurations for different portions of the drilling operation.

14. The method of claim 11 further comprising producing hydrocarbons from the well.

15. The method of claim 11 wherein calculating the transmissibility index comprises utilizing at least one frequency domain model to calculate at least one state of the at least two virtual sensors during one or more simulated drilling operations for each of the at least one surrogates;

and wherein the transmissibility index is based at least in part on at least one of the calculated states.

16. The method of claim 11 wherein the calculated at least one state comprises at least one of displacement, tilt angle, bending moment, and shear force.

17. The method of claim 11 wherein the calculated transmissibility index is a ratio between calculated accelerations of the at least two virtual sensors derived from one or more of the calculated states.

18. The method of claim 11 wherein a transmissibility index greater than 1 predicts that vibrations will increase between a first virtual sensor and a second virtual sensor.

19. The method of claim 11 wherein a transmissibility index less than 1 predicts that vibrations will decrease between a first virtual sensor and a second virtual sensor.

20. A modeling system comprising:

a processor;

a memory coupled to the processor; and

a set of computer readable instructions accessible by the processor, wherein the set of computer readable instructions are configured to;

a) construct at least one surrogate representing at least a portion of a bottom hole assembly, wherein the at least one surrogate includes at least two virtual sensors;

b) calculate a transmissibility index between the at least two virtual sensors for each of the at least one surrogates; and

c) output the transmissibility index for use in selecting an optimized bottom hole assembly configuration for a drilling operation based at least in part on the calculated transmissibility index.

21. The system of claim 20, wherein the transmissibility index is calculated utilizing at least one frequency-domain model to calculate at least one state of the at least two virtual sensors during one or more simulated drilling operations for each of the at least one surrogates.

22. The system of claim 20, wherein the output is provided as a graphical representation of the transmissibility index of a bottom hole assembly configuration at one or more points along the bottom hole assembly configuration.

23. A method of modeling drilling equipment to represent vibrational performance of the drilling equipment, the method comprising:

constructing at least one surrogate representing at least a portion of a bottom hole assembly disposed in a well;

utilizing a frequency domain model to calculate a sideforce at least at one contact point between the bottom hole assembly and the well, wherein the sideforce is calculated as a function of rotational speed for each surrogate;

determining at least one sideforce slope index as a function of rotational speed for the at least one contact point; and

displaying the calculated sideforce slope index as a function of rotational speed.

24. The method of claim 23 wherein a coefficient of friction at the least one contact point is assumed to be non-constant over the rotational speeds considered.

25. The method of claim 23 wherein the at least one sideforce slope indices are determined graphically.

26. The method of claim 23 wherein the at least one sideforce slope indices are determined numerically.

27. The method of claim 23 wherein the determined sideforce slope index is a combined index representative of a plurality of contact points between the bottom hole assembly and the well.

28. The method of claim 23 wherein a non-zero determined sideforce slope index predicts increased potential for vibration.

29. The method of claim 28 further comprising plotting the absolute value of the sideforce slope index as a function of rotational speed to determine a quantified potential for vibration.

30. The method of claim 29 further comprising identifying one or more contact points having greatest potential for vibration.

31. A method of drilling a well for use in the production of hydrocarbons, the method comprising;

constructing at least one surrogate representing at least a portion of a bottom hole assembly disposed in a well;

determining at least one sideforce slope index as a function of rotational speed for at least one contact point between the bottom hole assembly and the well;

selecting an optimized bottom hole assembly configuration for a drilling operation based at least in part on the determined at least one sideforce slope index; and

drilling a well with drilling equipment incorporating a bottom hole assembly at least substantially embodying the selected bottom hole assembly configuration.

32. The method of claim 31 wherein drilling the well is conducted according to a drilling plan developed based at least in part on the determined at least one sideforce slope index.

33. The method of claim 31 wherein selecting an optimized bottom hole assembly configuration comprises selecting different bottom hole assembly configurations for different portions of the drilling.

34. The method of claim 31 further comprising producing hydrocarbons from the well.

35. The method of claim 31 wherein determining at least one sideforce slope index comprises utilizing a frequency domain model to calculate a sideforce at least at one contact point between the bottom hole assembly and the well, wherein the sideforce is calculated as a function of rotational speed for each surrogate.

36. The method of claim 31 wherein a coefficient of friction at the least one contact point is assumed to be non-constant over the rotational speeds considered.

37. The method of claim 31 wherein the at least one sideforce slope indices are determined graphically.

38. The method of claim 31 wherein the at least one sideforce slope indices are determined numerically.

39. The method of claim 31 wherein the determined sideforce slope index is a combined index representative of a plurality of contact points between the bottom hole assembly and the well.

40. The method of claim 31 wherein a non-zero determined sideforce slope index predicts increased potential for vibration.

41. The method of claim 40 further comprising plotting the absolute value of the sideforce slope index as a function of rotational speed to determine a quantified potential for vibration.

42. The method of claim 41 further comprising identifying one or more contact points having greatest potential for vibration.

43. A modeling system comprising:

a processor;

a memory coupled to the processor; and

a set of computer readable instructions accessible by the processor, wherein the set of computer readable instructions are configured to;

construct at least one surrogate representing at least a portion of a bottom hole assembly disposed in a well;

determine at least one sideforce slope index as a function of rotational speed for at least one contact point between the bottom hole assembly and the well; and

output the at least one sideforce slope index for use in selecting an optimized bottom hole assembly configuration for a drilling operation based at least in part on the determined at least one sideforce slope index.

44. The system of claim 43, wherein the sideforce slope index is determined utilizing at least one frequency-domain model to calculate a sideforce at least at one contact point.

45. The system of claim 43, wherein the output is provided as a graphical representation of the sideforce slope index of a bottom hole assembly configuration at one or more points along the bottom hole assembly configuration.

46. A method of modeling drilling equipment to represent vibrational performance of the drilling equipment, the method comprising:

identifying two or more fundamental excitation modes for a drilling bottom hole assembly;

wherein each fundamental excitation mode is weighted relative to at least one other fundamental excitation mode; and

wherein the excitation modes are related to at least one vibration-related drilling parameter;

constructing at least one surrogate representing at least a portion of a bottom hole assembly;

utilizing a frequency-domain model to simulate a response of the at least one surrogate to excitations corresponding with the identified fundamental excitation modes;

determining one or more performance indices for the simulated surrogate, wherein at least one of the performance indices is based at least in part on the simulated response of the surrogate at least at two fundamental excitation modes and on the relative weight of the at least two fundamental excitation modes; and

utilizing the one or more performance indices in selecting at least one of one or more bottom hole assembly configurations and one or more drilling plans for use in drilling operations.

47. The method of claim 46, wherein the one or more performance indices are selected from at least one of an end point curvature index, a BHA strain energy index, an average transmitted strain energy index, a transmitted strain energy index, a root-mean-square BHA sideforce index, a root-mean-square BHA torque index, a total BHA sideforce index, a total BHA torque index, a sideforce slope index, a transmissibility index, and any mathematical combination thereof.

48. The method of claim 46, further comprising drilling a well using at least one of a) the selected one or more bottom hole assembly configurations and b) the selected one or more drilling plans.

49. The method of claim 46, wherein the two or more fundamental excitation modes are identified from field data using a method comprising:

obtaining field-data dynamic measurements of at least one dynamic state of a drilling bottom hole assembly, wherein each of the measurements is associated with at least one node in the bottom hole assembly;

processing the field-data measurements to obtain one or more windows having frequency-domain spectra of at least one of the measured dynamic states; and

identifying two or more fundamental excitation modes in the one or more windows;

wherein the fundamental excitation modes correspond to regions of the frequency-domain spectra having spectral peaks; and

wherein each of the two or more fundamental excitation modes is weighted relative to at least one other fundamental excitation mode.

50. The method of claim 49 wherein the at least one dynamic state is selected from one or more of rotary speed, displacement, velocity, acceleration, bending strain, bending moment, tilt angle, and force.

51. The method of claim 49, wherein the field-data is collected using one or more near-bit sensors.

52. The method of claim 49, wherein the field-data measurements are processed using one or more Fourier transforms to provide frequency-domain spectra.

53. The method of claim 49, wherein the one or more windows each present measured data for an interval in a drilling history, wherein the interval is for at least one of a period of time, a depth range, and a rotary speed applied during the drilling.

54. The method of claim 53, wherein the one or more windows present intervals of nearly constant rotary speed, and wherein the one or more identified fundamental excitation modes is associated with one or more multiples of the rotary speed having spectral peaks.

55. The method of claim 49, further comprising drilling a well using at least one of a) the selected one or more bottom hole assembly configurations and b) the selected one or more drilling plans.

56. The method of claim 46, wherein the two or more fundamental excitation modes are identified from simulated data and field data using a method comprising:

obtaining measurements of at least one parameter of a drilling bottom hole assembly indicative of vibrational performance, wherein the measurements relate to one or more nodes on the drilling bottom hole assembly;

constructing a surrogate representing at least a portion of the drilling bottom hole assembly;

utilizing a frequency-domain model to simulate a response of the surrogate to dynamic excitations at one or more reference nodes corresponding to the nodes on the drilling bottom hole assembly, wherein a response is simulated for each of at least two excitation modes;

determining a vibrational performance index for each of the at least two excitation modes based at least in part on the response of the surrogate to the dynamic excitations;

comparing the at least two determined vibrational performance indices with the obtained measurements to determine the relative contribution of each excitation mode to the measured vibration performance; and

weighting each of the excitation modes according to the respective relative contributions to determine at least two fundamental excitation modes.

57. The method of claim 56, wherein the at least one parameter is selected from one or more of rate of penetration, mechanical specific energy, measured downhole acceleration, measured downhole velocity, bending moment, bending strain, shock count, and stick-slip vibrations.

58. The method of claim 56, wherein the dynamic excitations of the surrogate are applied by perturbing at least one model state selected from displacement, tilt angle, moment, and force.

59. The method of claim 56, wherein the at least two determined vibrational performance indices are summed with multiplicative non-negative coefficients to obtain a combined surrogate performance index for comparison with the obtained measurements;

wherein comparing the surrogate vibrational performance index with the obtained measurements comprises varying the non-negative coefficients for each performance index until differences between the combined performance index and the obtained measurements are at least substantially minimized to establish excitation coefficients corresponding to at least two weighted fundamental excitation modes.

60. The method of claim 56, further comprising drilling a well using at least one of a) the selected one or more bottom hole assembly configurations and b) the selected one or more drilling plans.

61. The method of any one of claims 48, 55, and 60 further comprising producing hydrocarbons from the well.

62. A method of drilling a well for use in the production of hydrocarbons, the method comprising;

identifying two or more fundamental excitation modes for a drilling bottom hole assembly;

wherein each fundamental excitation mode is weighted relative to at least one other fundamental excitation mode; and

wherein the excitation modes are related to at least one vibration-related drilling parameter;

constructing at least one surrogate representing at least a portion of a bottom hole assembly;

utilizing a frequency-domain model to simulate a response of the at least one surrogate to excitations corresponding with the identified fundamental excitation modes;

determining one or more performance indices for the simulated surrogate, wherein at least one of the performance indices is based at least in part on the simulated response of the surrogate at least at two fundamental excitation modes and on the relative weight of the at least two fundamental excitation modes;

utilizing the one or more performance indices in selecting at least one of one or more bottom hole assembly configurations and one or more drilling plans for use in drilling operations; and

drilling a well with at least one of

     1) drilling equipment incorporating a bottom hole assembly at least substantially embodying the selected one or more bottom hole assembly configurations and

     2) the selected one or more drilling plans.

63. The method of claim 62 wherein selecting a bottom hole assembly configuration comprises selecting different bottom hole assembly configurations for different portions of the drilling.

64. The method of claim 62 further comprising producing hydrocarbons from the well.

65. The method of claim 62 wherein the two or more fundamental excitation modes are identified from field data.

66. The method of claim 62 wherein the two or more fundamental excitation modes are identified from simulated data and field data.