WELLBORE TELEMETRY AND NOISE CANCELLATION SYSTEMS AND METHOD FOR THE SAME

• US 20070263488A1
• Filed: 12/21/2006
• Published: 11/15/2007
• Est. Priority Date: 05/10/2006
• Status: Active Grant

• Current Assignee: Schlumberger Technology Corporation (SLB)
• Original Assignee: Schlumberger Technology Corporation (SLB)
• Inventors: CLARK, BRIAN
• Granted Patent: US 8,004,421 B2
• Time in Patent Office: Days
• US Class Current: 367/87
• CPC Class Codes: E21B 47/12 Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
• CPC Class Codes: E21B 47/13 by electromagnetic energy, e.g. radio frequency
• CPC Class Codes: E21B 47/14 using acoustic waves
• CPC Class Codes: E21B 47/18 through the well fluid , e.g. mud pressure pulse telemetry
• CPC Class Codes: G01V 11/002 Details, e.g. power supply systems for logging instruments, transmitting or recording data, specially adapted for well logging, also if the prospecting method is irrelevant means for transmitting well survey signals E21B47/12; signal transmission systems in general G08C; transmission in general H04B

Abstract

A method of signal processing includes providing at least a first pressure sensor and a second pressure sensor spaced in a drilling system and using an algorithm to separate the downwardly propagating waves from the upwardly propagating waves. In one or more examples, an algorithm may include determining a velocity of pressure signals in a wellbore, time-shifting and stacking pressure signals from at least the first pressure sensor and the second pressure sensor to determine a downwardly propagating noise signal, and subtracting the downwardly propagating noise signal from at least the signal from the first pressure sensor.

Claims

1. A method of signal processing, comprising:

providing at least a first pressure sensor and a second pressure sensor spaced in a drilling system; and

using an algorithm to separate the downwardly propagating waves from the upwardly propagating waves.

2. The method of claim 1, wherein using an algorithm to separate the downwardly propagating waves from the upwardly propagating waves comprises:

determining a velocity of pressure signals in a wellbore;

time-shifting and stacking pressure signals from at least the first pressure sensor and the second pressure sensor to determine a downwardly propagating noise signal; and

subtracting the downwardly propagating noise signal from at least the signal from the first pressure sensor.

3. The method of claim 2, further comprising:

subtracting the downwardly propagating noise signal from the signal from at least the second pressure sensor; and

time-shifting and stacking at least the signal from the first pressure sensor and the signal from the second pressure sensor to obtain the upwardly propagating data signal.

4. The method of claim 3, wherein

providing at least a first pressure sensor and a second pressure sensor comprises providing the first pressure sensor, the second pressure sensor, and a third pressure sensor, and wherein:

time-shifting and stacking at least the signal from the first pressure sensor and the signal from the second pressure sensor to determine a downwardly propagating noise signal comprises time-shifting and stacking the signal from the first, second, and third pressure sensors; and

wherein

subtracting the downwardly propagating noise signal from at least the signal from the first pressure sensor comprises subtracting the downwardly propagating noise signal from the signals from the first, second, and third pressure sensors.

5. The method of claim 4, wherein:

time-shifting and stacking the signals from the first, second, and third pressure sensors to determine the downwardly propagating noise signal is performed using the following equation;

N_D(t)={S₁(t)+S₂(t+(Z2−

Z1)/V)+S₃(t+(Z3−

Z1)/V)}/3; and

wherein

subtracting the downwardly propagating noise signal from the signals from the first, second, and third pressure sensors is performed using the following equations;

R₁(t)=S₁(t)−

N_D(t),

R₂(t)=S₂(t)−

N_D(t+(Z2−

Z1)/V),

R₃(t)=S₃(t)−

N_D(t+(Z3−

Z1)/V).

6. The method of claim 2, further comprising transmitting pressure signals from at least the first and second pressure sensor to a surface location.

7. The method of claim 6, wherein the pressure signals are transmitted through one of a wired drill pipe, an electromagnetic telemetry tool, a wireline cable, a fiber-optic cable, and a wireless communication device.

8. The method of claim 3, wherein the upwardly propagating data signal comprises an MW) signal.

9. The method of claim 2, wherein determining the velocity of signals in the wellbore fluid comprises:

determining at least one cross-correlation function between the signals from at least the first pressure sensor and the second pressure sensor for downwardly propagating waves;

determining a maximum value for the at least one cross-correlation function; and

determining the velocity of the signals in the wellbore fluid based on a maximum value of the at least one cross-correlation function.

10. The method of claim 9, wherein:

the cross-correlation function comprises;

$C<br><br><br><br>12<br><br>\left(d\right)=\underset{k=0}{\overset{m-1}{\sum <br><br>}}<br><br>\left\{\left[S<br><br><br><br>1<br><br>\left(\mathrm{tk}\right)-\stackrel{\_}{S<br><br><br><br>1}\right]·<br><br>\left[S<br><br><br><br>2<br><br>\left(\mathrm{tj}\right)-\stackrel{\_}{S<br><br><br><br>2}\right]\right\};<br><br>\mathrm{and}$

determining the velocity of signals in the wellbore fluid comprises solving for V, using the maximum value of the cross-correlation function and the following equation;

d·

Δ

t=(Z₂−

Z₁)/V.

11. The method of claim 9, wherein determining at least one cross-correlation function between at least the first pressure sensor and the second pressure sensor for downwardly propagating waves comprises:

determining a cross-correlation between the signals from the first pressure sensor and the second pressure sensor;

determining a cross-correlation between the signals from the first pressure sensor and a third pressure sensor; and

determining a cross-correlation between the signals from the second pressure sensor and the third pressure sensor.

12. The method of claim 1, wherein providing at least a first pressure sensor and a second pressure sensor spaced in a drilling system comprises:

positioning a wireline device within the drilling system,

wherein the wireline device includes the at least a first pressure sensor and a second pressure sensor.

13. The method of claim 1, wherein providing a first pressure sensor and a second pressure sensor spaced in a drilling system comprises:

positioning a fiber-optic device within the drilling system,

wherein the fiber-optic device includes the at least a first pressure sensor and a second pressure sensor.

14. The method of claim 1, wherein providing at least a first pressure sensor and a second pressure sensor spaced in a drilling system comprises:

positioning the first pressure sensor, the second pressure sensor, and a third pressure sensor within one selected from a drill string, and a casing.

15. The method of claim 1, wherein using an algorithm to separate the downwardly propagating waves from the upwardly propagating waves comprises using f-k processing techniques.

16. The method of claim 15, wherein using f-k processing techniques comprises applying a fourier transform of signals from at least the first pressure sensor and the second pressure sensor from spatial and temporal dimensions into data in frequency and wavenumber dimensions.

17. The method of claim 16, wherein the data in frequency and wavenumber dimensions are multiplied by factors to produce a reduced data set where at least one of an amplitude and a frequency of downwardly propagating waves associated with noise is minimized.

18. The method of claim 17, further comprising applying an inverse fourier transform on the reduced data set to transform the data set back to the spatial and temporal dimensions.

19. The method of claim 1, wherein the downwardly propagating waves comprise noise and the upwardly propagating waves comprise a data signal.

20. The method of claim 1, wherein the downwardly propagating waves comprise a data signal and the upwardly propagating signal comprises one of noise and a second data signal.

21. A wellbore communication system, comprising:

a plurality of pressure sensors spaced within a drilling system along a drilling fluid flow path and communicatively coupled to a surface system; and

a mud pulse telemetry system positioned within a downhole tool.

22. The wellbore communication system of claim 21, further comprising:

a section of wired drill pipe communicatively coupled to the surface system;

wherein the plurality of pressure sensors are communicatively coupled to the section of wired drill pipe.

23. The wellbore communication system of claim 22, wherein the plurality of pressure sensors are positioned within respective subs, and wherein the respective subs are connected within section of wired drill pipe of the drill string.

24. The wellbore communication system of claim 21, wherein the plurality of pressure sensors are communicatively coupled to the surface by one selected from an electromagnetic telemetry system, a wireline system, a fiber optic system, and a wireless communication system.

25. The wellbore communication system of claim 21, wherein the plurality of pressure sensors are disposed within one selected from a drill pipe, a casing, a riser, and a coiled tubing.

26. The wellbore communication system of claim 21, wherein the plurality of pressure sensors are spaced between one quarter of a wavelength and three quarters of a wavelength for a communication signal frequency.

27. The wellbore communication system of claim 21, wherein the plurality of pressure sensors are spaced about one quarter of a wavelength for a communication signal frequency.

28. The wellbore communication system of claim 21, wherein the plurality of pressure sensors are disposed on a wireline device that is disposed within the drilling system.

29. The wellbore communication system of claim 21, wherein the plurality of pressure sensors are disposed on a fiber-optic device that is disposed within the drilling system.

30. The wellbore communications system of claim 21, wherein the plurality of pressure sensors are positioned below one of a Kelly or a top-drive system.

31. The wellbore communications system of claim 30, wherein the plurality of pressure sensors are positioned in a drill pipe.

32. The method of claim 21, where in the plurality of pressure sensors comprises three or more pressure sensors.

33. A method for wellbore communications, comprising:

obtaining a first corrected pressure signal and a downwardly propagating noise signal from at least a first pressure sensor;

computing a cross-correlation function between the first corrected pressure signal and the downwardly propagating noise signal for at least the first pressure sensor;

computing the standard deviation of the downwardly propagating noise signal;

computing a reflection coefficient for the downwardly propagating noise signal;

computing the reflected, upwardly propagating noise signal, and

subtracting the upwardly propagating noise signal from the first corrected pressure signal.

34. The method of claim 33, wherein:

the cross-correlation function comprises;

$\mathrm{CD}<br><br>\left(d\right)=\underset{k=0}{\overset{m-1}{\sum <br><br>}}<br><br>\left\{\left[R<br><br>\left(\mathrm{tk}\right)-\stackrel{\_}{R}\right]·<br><br>\left[N_D<br><br>\left(\mathrm{tj}\right)-\stackrel{\_}{N_D}\right]\right\};<br><br>$

computing a reflection coefficient for the downwardly propagating noise signal comprises averaging the following equation over a plurality of measurements;

$A·<br><br>{\mathrm{<br><br>}}^{\mathrm{<br><br>\phi <br><br>}}=\frac{〈<br><br>C<br><br><br><br>3<br><br>D<br><br>\left(d\right)〉<br><br>}{\left(m-1\right)<br><br>〈<br><br>{\mathrm{\sigma <br><br>}}_N^2〉<br><br>};<br><br>\mathrm{and}$

subtracting the upwardly propagating noise is performed using the following equation;

₃(t)=R₃(t)−

Ae^iφ

·

N_D(t+Tc−

Ta),

35. The method of claim 33, wherein computing the standard deviation of the downwardly propagating noise signal is preformed in a time window corresponding to a maximum value for the cross-correlation function.

36. The method of claim 33, subtracting an upwardly propagating noise signal from the first corrected pressure signal obtains a first twice corrected pressure signal, and further comprising:

obtaining a second corrected pressure signal and a downwardly propagating noise signals from a second pressure sensor;

computing a cross-correlation function between the second corrected pressure signal and the downwardly propagating noise signal for the second pressure sensor;

computing the standard deviation of the downwardly propagating noise signal from the second pressure sensor;

computing a reflection coefficient for a mud pump noise at the second pressure sensor;

subtracting an upwardly propagating noise signal at the second pressure sensor from the second corrected pressure signal to obtain a twice corrected second pressure signal; and

time-shifting and stacking the first twice corrected pressure signal and the second twice corrected pressure signal.

37. A method for wellbore communications, comprising:

obtaining signals representing pressure measurements over time at a first pressure sensor, a second pressure sensor, and a third pressure sensor positioned within a drilling system;

determining a cross-correlation function between the signals from the first pressure sensor and the second pressure sensor for a downwardly propagating noise signal;

determining a cross-correlation function between the signals from the second pressure sensor and the third pressure sensor for the downwardly propagating noise signal;

determining a maximum value for the each cross-correlation function;

determining the velocity of the signals in the wellbore fluid based on the maximum values for the cross-correlation functions.

time-shifting and stacking the signals from the first, second, and third pressure sensors to determine a downwardly propagating noise signal;

subtracting the downwardly propagating noise signal from the signal from the first, second, and third pressure sensors to obtain a first corrected pressure signal, a second corrected pressure signal, and a third corrected pressure signal;

computing a cross-correlation function between the corrected pressure signal and the downwardly propagating noise signal for first, second, and third corrected pressure signals;

computing the standard deviation of the downwardly propagating noise signal;

computing a reflection coefficient for downwardly propagating noise signal;

computing the reflected, upwardly propagating noise signal,

subtracting the upwardly propagating noise signal from the corrected pressure signal for the first, second, and third sensors to obtain a twice corrected first pressure signal, a twice corrected second pressure signal, and a twice corrected third pressure signal; and

time-shifting and stacking the twice corrected first pressure signal, the twice corrected second pressure signal, and the twice corrected third pressure signal to obtain an upwardly propagating data signal.