Data compression method for use in wellbore and formation characterization

• US 6,405,136 B1
• Filed: 06/23/2000
• Issued: 06/11/2002
• Est. Priority Date: 10/15/1999
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Original Assignee: Schlumberger Technology Corporation (Schlumberger NV)
• Inventors: Lovell, John, Fredette, Mark, Li, Qiming
• Primary Examiner(s): McElheny, Jr., Donald E.
• Application Number:
  US09/602,860
• Time in Patent Office: 718 Days
• Field of Search: 702/10, 702/9, 702/7, 702/8, 367/81-83, 333/04, 333/12, 333/13, 731/520.1, 731/520.3, 731/524.5, 731/524.3, 731/524.4, 731/524.6, 175/40, 175/45, 175/50, 175/44, 340/853.1, 340/853.6, 340/854.1, 340/854.6, 340/855.4, 340/855.5, 340/855.6, 340/855.7
• US Class Current: 702/10
• CPC Class Codes: E21B 47/04 Measuring depth or liquid level
• CPC Class Codes: H03M 7/30 Compression speech analysis-synthesis for redundancy reduction G10L19/00; for image communication H04N; Expansion; Suppression of unnecessary data, e.g. redundancy reduction

Abstract

A method is disclosed for compressing a frame of data representing parameter values, a time at which each parameter value was recorded, and an orientation of a sensor at the time each parameter value was recorded. Generally the method includes performing a two-dimensional transform on the data in the orientation domain and in a domain related to the recording time. In one embodiment, the method includes calculating a logarithm of each parameter value. In one embodiment, the 2-D transform includes generating a Fourier transform of the logarithm of the parameter values in the azimuthal domain, generating a discrete cosine transform of the transform coefficients in the time domain. This embodiment includes quantizing the coefficients of the Fourier transform and the discrete cosine transform. One embodiment of the method is adapted to transmit resistivity measurements made by an LWD instrument in pressure modulation telemetry so that while-drilling images of a wellbore can be generated. The one embodiment includes encoding the quantized coefficients, error encoding the encoded coefficients, and applying the error encoded coefficients to the pressure modulation telemetry.

Claims

1. A method for compressing a frame of data representing parameter values, a time at which each of the parameter values was recorded, and a corresponding azimuthal orientation of each of the parameter values at the time each was recorded, comprising:

range compressing the parameter values;

selecting an azimuthal reference so that the parameter values are substantially periodic with respect to the azimuthal reference;

performing a two-dimensional transform to the scale compressed parameter values, an output of the transform comprising a set of coefficients; and

quantizing the coefficients.

2. The method as defined in claim 1 wherein the two-dimensional transform comprises a Fourier transform in the azimuthal domain and a discrete cosine transform in a domain corresponding to the time of recording.

3. The method as defined in claim 2 wherein the corresponding domain is the depth domain.

4. The method as defined in claim 2 wherein the corresponding domain is the time domain.

5. The method as defined in claim 1 further comprising encoding the quantized coefficients.

6. The method as defined in claim 5 wherein the encoding the quantized coefficients comprises efficient entropy encoding.

7. The method as defined in claim 6 further comprising error-correction encoding the encoded quantized coefficients.

8. The method as defined in claim 7 wherein the error-correction encoding comprises interleaved encoding, the interleaved encoding comprising:

separating bits in the frame of data into words each having equal length;

selecting correspondingly positioned bits in each of the words and grouping the selected bits to form new words; and

Hamming encoding the new words.

9. The method as defined in claim 8 further comprising applying the Hamming encoded new words to a selected location in a telemetry sequence, and transmitting the Hamming encoded new words to a recording unit.

10. The method as defined in claim 9 wherein the telemetry sequence comprises measurement while drilling telemetry.

11. The method as defined in claim 1 wherein the parameter comprises electrical resistivity of earth formations penetrated by a wellbore.

12. The method as defined in claim 1 wherein the parameter comprises acoustic reflectance amplitude of earth formations penetrated by a wellbore.

13. The method as defined in claim 1 wherein the parameter comprises gamma—

gamma density of earth formations penetrated by a wellbore.

14. The method as defined in claim 1 wherein the range compressing comprises calculating a logarithm of each of the parameter values.

15. The method as defined in claim 1 wherein the range compressing comprises calculating a fractional exponential of each of the parameter values.

16. The method as defined in claim 2 wherein the azimuthal reference is selected to minimize an energy in sine terms in the Fourier transform.

17. The method as defined in claim 16 wherein a dip azimuth of earth formations is estimated by determining a geographic orientation of the azimuthal references selected to minimize the energy of the sine terms.

64. The method as defined in claim 1 wherein the parameter comprises one of photoelectric factor or porosity of an earth formation penetrated by a wellbore.

65. The method as defined in claim 1 wherein the parameter comprises instrument standoff in a wellbore.

66. The method as defined in claim 1 wherein the parameter comprises a wellbore caliper.

67. The method as defined in claim 1 wherein the parameter comprises an acoustic signal.

68. The method as defined in claim 1 wherein the parameter comprises a nuclear magnetic resonance property of an earth formation penetrated by a wellbore.

18. A method for acquiring and communicating image-producing data to a surface recording unit, comprising:

measuring a value of a parameter of an earth formation penetrated by a wellbore at azimuthally spaced apart positions in the wellbore;

determining an azimuthal orientation at which each of the values of the parameter is measured;

determining a time at which each of the values of the parameter is measured;

compressing the parameter values;

encoding the compressed parameter values; and

applying the encoded, compressed parameter values to a selected position in a telemetry format for transmission to the surface recording unit.

19. The method as defined in claim 18 wherein the parameter comprises electrical resistivity.

20. The method as defined in claim 18 wherein the parameter comprises acoustic reflectance amplitude.

21. The method as defined in claim 18 wherein the parameter comprises gamma—

gamma density.

22. The method as defined in claim 18 wherein the telemetry comprises measurement while drilling telemetry.

23. The method as defined in claim 18 further comprising:

detecting the encoded compressed, parameter values at the recording unit from the telemetry;

decoding and decompressing the encoded, compressed parameter values;

reconstructing the values of the parameter and the corresponding azimuthal orientations;

adjusting the corresponding azimuthal orientations with respect to a trajectory of the wellbore proximate to a position therein at which the parameter values were measured to provide an orientation of each of the parameter values with respect to a selected geographic reference; and

developing an image from the reconstructed values and corresponding geographic orientations.

24. The method as defined in claim 18 wherein the compressing comprises identifying an azimuthal reference, performing a Fourier transform to the parameter values in the azimuthal domain with respect to the azimuthal reference and performing a discrete cosine transform to the Fourier-transformed parameter values in a domain corresponding to the time of recording, the Fourier transform and the discrete cosine transform providing an output comprising coefficients.

25. The method as defined in claim 24 wherein the corresponding domain is the depth domain.

26. The method as defined in claim 24 wherein the corresponding domain is the time domain.

27. The method as defined in claim 24 further comprising quantizing the output coefficients.

28. The method as defined in claim 27 further comprising encoding the quantized coefficients.

29. The method as defined in claim 28 wherein the encoding comprises efficient entropy encoding.

30. The method as defined in claim 28 further comprising error-correction encoding the encoded quantized coefficients.

31. The method as defined in claim 30 wherein the error-correction encoding comprises interleaved encoding, the interleaved encoding comprising:

separating bits in a frame of data into words each having equal length;

selecting correspondingly positioned bits in each of the words and grouping the selected bits to form new words; and

Hamming encoding the new words.

32. The method as defined in claim 24 wherein the azimuthal reference is selected for the azimuthal orientation, so as to minimize an energy in sine terms in the Fourier transform.

33. The method as defined in claim 32 wherein a dip azimuth of earth formations is estimated by determining a geographic orientation of the azimuthal references selected to minimize the energy of the sine terms.

69. The method as defined in claim 18 wherein the parameter comprises one of photoelectric factor or porosity.

70. The method as defined in claim 18 wherein the parameter comprises a wellbore caliper.

71. The method as defined in claim 18 wherein the parameter comprises an acoustic signal.

72. The method as defined in claim 18 wherein the parameter comprises a nuclear magnetic resonance property of the earth formation.

34. A method for determining rate of penetration of a drilling assembly in a wellbore, comprising:

measuring, near the drilling assembly, a property of earth formations penetrated by the drilling assembly, the measuring performed by sensors at axially spaced apart locations;

recording a time at which each of the measurements of the property are made;

recording an azimuthal orientation of the sensors at the time each of the measurements is made;

correlating azimuthally corresponding ones of the measurements made at a first one of the spaced apart locations to measurements made at a second one of the spaced apart locations;

determining from the correlating when the first and the second one of the spaced apart location have made measurements in substantially the same earth formation; and

calculating the rate of penetration from a difference in time between the measurements made in the substantially same earth formation at the first and second spaced apart locations and from a distance between the first and second spaced apart locations.

35. The method as defined in claim 34 wherein the measured property of the formation comprises electrical resistivity.

36. The method as defined in claim 34 wherein the measured property of the formation comprises acoustic reflectance amplitude.

37. The method as defined in claim 34 wherein the measured property comprises gamma—

gamma density.

38. The method as defined in claim 34 further comprising:

correlating the rate of penetration determined from the measurements at the first and the second axially spaced apart locations, to time correspondent measurements of a depth of the drilling assembly made by a sensor at the earth'"'"'s surface; and

adjusting the measurements of the depth of the drilling assembly made by the sensor at the earth'"'"'s surface for compression and extension of a drill pipe connecting the drilling assembly to a drilling rig at the earth'"'"'s surface.

39. The method as defined in claim 34 further comprising:

making the measurements of the property at azimuthally spaced apart positions;

calculating, in an instrument forming part of the drilling assembly an axial displacement of bed boundaries of the earth formations with respect to orientation about the circumference of the wellbore by correlating axially spaced apart, azimuthally correspondent ones of the measurements; and

determining a dip of the bed boundaries from the axial displacement and from measurements of trajectory of the wellbore.

40. The method as defined in claim 39 wherein the axial displacement is transmitted to the earth'"'"'s surface by measurement-while-drilling telemetry.

41. The method as defined in claim 39 wherein the dip is calculated in the instrument and is transmitted to the earth'"'"'s surface by the measurement-while-drilling telemetry.

42. The method as defined in claim 39 wherein the axial displacement is calculated by correlating a first frame of measurements of the property to a second frame of measurements of the property, the first frame and second frame each comprising measurements made over a selected time interval, the instrument forming part of the drilling assembly moving along the wellbore during each of the selected time intervals.

43. A method for determining dip of earth formations penetrated by a wellbore, comprising:

moving an instrument forming part of a drilling assembly along the wellbore;

measuring a property of the earth formations at azimuthally spaced apart positions using at least one sensor disposed at a selected axial position along the instrument, the measurements each including a record of an azimuthal orientation and a time at which the measurements are made;

determining an axial position of the instrument along the wellbore with respect to the time records, so as to determine an axial position of each of the measurements of the formation property;

determining an axial displacement of at least one layer boundary in the earth formations by correlating measurements made at selected, corresponding azimuthal orientations and at a plurality of the determined axial positions; and

calculating the dip by combining the axial displacement with a measurement of the trajectory of the wellbore proximate the measurements of the formation property.

44. The method as defined in claim 43 wherein the azimuthally spaced apart positions are generated by rotating the instrument within the wellbore.

45. The method as defined in claim 43 wherein the azimuthally spaced apart positions are generated by providing a plurality of sensors on the instrument at azimuthally spaced apart positions.

46. The method as defined in claim 43 wherein the property of the formations comprises electrical resistivity.

47. The method as defined in claim 43 wherein the property of the formations comprises acoustic reflectance amplitude.

48. The method as defined in claim 43 wherein the property of the formations comprises gamma-gamma density.

49. The method as defined in claim 43 wherein the dip is calculated in the instrument in the wellbore and is transmitted to the earth'"'"'s surface by measurement-while-drilling telemetry.

50. A method for determining dip of earth formations penetrated by a wellbore, comprising:

moving an instrument along the wellbore;

measuring a property of the earth formations at azimuthally spaced apart positions around the wellbore using at least one sensor disposed at a selected axial position along the instrument, the measurements each including a record of an azimuthal orientation and a time at which the measurements are made;

correlating the measurements made by the at least one sensor to identify boundaries of layers in the formation measured by the at least one sensor, and determining a time difference between which the at least one sensor having measured corresponding ones of the layer boundaries;

computing from this the difference an estimate of formation dip that would correspond to a fixed rate of movement of the instrument along the wellbore;

transmitting to the earth'"'"'s surface the estimate of formation dip;

making a measurement at the earth'"'"'s surface of the rate of movement of the instrument along the wellbore;

using the measurement of movement made at the surface to convert the transmitted dip estimate into an estimate of the apparent dip of the corresponding layer boundaries;

combining the estimate of apparent dip with a measurement of the trajectory of the wellbore proximate the measurements made of the formation property to provide an estimate of the dip of the formation layer boundaries.

51. The method as defined in claim 50 wherein the azimuthally spaced apart positions are generated by rotating the instrument within the wellbore.

52. The method as defined in claim 50 wherein the azimuthally spaced apart positions are generated by providing a plurality of sensors on the instrument at azimuthally spaced apart positions.

53. The method as defined in claim 50 wherein the property of the formations comprises electrical resistivity.

54. The method as defined in claim 50 wherein the property of the formations comprises acoustic reflectance amplitude.

55. The method as defined in claim 50 wherein the property of the formations comprises gamma-gamma density.

56. A method for determining dip of earth formations penetrated by a wellbore, comprising:

moving an instrument along the wellbore;

measuring a property of the earth formations at azimuthally spaced apart positions using at least one sensor disposed at a selected axial position along the instrument, the measurements each including a record of an azimuthal orientation and a time at which the measurements are made;

selecting an azimuthal reference which minimizes a sinusoidal component of an azimuthal Fourier transform of the data with respect to that reference;

generating a discrete cosine transform of the Fourier-transformed data;

identifying from the resulting 2D transformed data a corresponding apparent dip of the formation with respect to the wellbore;

combining the corresponding apparent dip with a measurement of the trajectory of the wellbore proximate the measurements of the formation property to provide an estimate of the dip of the earth formation.

57. The method as defined in claim 56 wherein the azimuthally spaced apart positions are generated by rotating the instrument within the wellbore.

58. The method as defined in claim 56 wherein the azimuthally spaced apart positions are generated by providing a plurality of sensors on the instrument at azimuthally spaced apart positions.

59. The method as defined in claim 56 wherein the apparent dip of the formation with respect to the wellbore is computed from a non-sinusoidal component of the Fourier transformed data.

60. The method defined in claim 56 wherein the effect of the apparent dip of the formation with respect to the wellbore is removed from the 2D transformed data and the resulting data is then compressed for transmission to the surface.

61. The method as defined in claim 56 wherein the property of the formations comprises electrical resistivity.

62. The method as defined in claim 56 wherein the property of the formations comprises acoustic reflectance amplitude.

63. The method as defined in claim 56 wherein the property of the formations comprises gamma—

gamma density.