Method and apparatus for communicating data in a wellbore and for detecting the influx of gas

• US 5,592,438 A
• Filed: 08/18/1993
• Issued: 01/07/1997
• Est. Priority Date: 06/14/1991
• Status: Expired due to Fees

• Current Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Original Assignee: Baker Hughes Incorporated (Baker Hughes Company)
• Inventors: Gibbons, Frank L., Patel, Ashok, Leggett, James V. III, Owens, Steven C., Rorden, Louis H.
• Primary Examiner(s): Lobo, Ian J.
• Application Number:
  US08/108,958
• Time in Patent Office: 1,238 Days
• Field of Search: 367/83, 367/912, 367/82, 340/854.3, 340/854.4, 73/151, 73/152, 73/155
• US Class Current: 367/83
• CPC Class Codes: E21B 47/107 using acoustic means
• CPC Class Codes: E21B 47/16 through the drill string or casing , e.g. by torsional acoustic waves
• CPC Class Codes: E21B 47/18 through the well fluid , e.g. mud pressure pulse telemetry
• CPC Class Codes: E21B 47/20 by modulation of mud waves, e.g. by continuous modulation
• CPC Class Codes: E21B 47/24 by positive mud pulses using a flow restricting valve within the drill pipe
• CPC Class Codes: G08C 2201/51 Remote controlling of devices based on replies, status thereof
• CPC Class Codes: G08C 23/00 Non-electrical signal transmission systems, e.g. optical systems
• CPC Class Codes: G08C 23/02 using infrasonic, sonic or ultrasonic waves
• CPC Class Codes: Y10S 367/912 Particular transducer

Abstract

A transducer is described especially for use in providing acoustic transmission in a borehole. The transducer includes a multiple number of magnetic circuit gaps and electrical windings that have been found to provide the power necessary for acoustic operation in a borehole while still meeting the stringent dimensional criteria necessitated by boreholes. Various embodiments conforming to the design are described. Moreover, the invention includes transition and reflector sections, as well as a directional coupler and resonator arrangement particularly adapted for borehole acoustic communication.

An acoustic communication system is described especially designed for use in providing acoustic transmission of information in a borehole. The communication system comprises a surface transceiver and at least one downhole transceiver. The surface transceiver operates in conjunction with a host computer that sends commands to the downhole transceiver. Subsequently, the downhole transceiver transmits encoded data from subsurface, borehole sensors to the surface transceiver. The preferred embodiment uses Minimum Shift Keying (MSK) modulation for both transmitting commands to the downhole unit and for transmitting data to the surface transceiver. To facilitate operation of a coherent communication system in the inhospitable environment of a borehole, the acoustic channel is characterized to enable the system to choose the best possible frequency and bandwidth for communication transmission. Additionally, the system achieves synchronous operation by transmitting synchronization signals between the downhole transceiver and the surface transceiver prior to the units exchanging commands and data.

Claims

1. An acoustic communication apparatus for use in a wellbore having a plurality of concentrically nested tubular strings disposed therein, with at least one fluid column defined therein selected as a communication channel, comprising:

a transducer in force-transferring communication with said communication channel;

a housing for securing said transducer in a selected location within said wellbore, said housing affecting an acoustic admittance of said communication channel; and

at least one impedance matching member, dimensioned in (1), cross-sectional area and (2) length with respect to at least one of (1) said communication channel, (2) said housing, and (3) at least one probable acoustic communication frequency to minimize reflection of acoustic energy at said housing.

2. An acoustic communication apparatus according to claim 1, wherein said at least one impedance matching member is located proximate said housing.

3. An acoustic communication apparatus according to claim 1, wherein said at least one impedance matching member is located intermediate said housing and a remotely-located communication node.

4. An acoustic communication apparatus according to claim 1:

wherein said communication channel comprises an annular region defined by said concentrically nested tubular strings;

wherein said housing extends into, and partially obstructs, said annular region, thereby affecting acoustic admittance of said communication channel; and

wherein said at least one impedance matching member is sized to also partially obstruct said annular region, but to a lesser extent than said housing.

5. An acoustic communication apparatus according to claim 4:

wherein said at least one impedance matching member is radially dimensioned to provide a surrounding unobstructed annular region which has a predetermined cross-sectional area.

6. An acoustic communication apparatus according to claim 5:

wherein said predetermined cross-sectional area comprises a geometric average of the mathematical product of (a) the cross-sectional area of an unobstructed portion of said annular region and (b) the cross-sectional area of said annular region surrounding said housing.

7. An acoustic communication apparatus according to claim 4:

wherein said at least one impedance matching member has a length which is approximately equal to one-quarter wavelength of said at least one probable acoustic communication frequency.

8. An acoustic communication apparatus for use in a wellbore having a plurality of concentrically nested tubular strings disposed therein, with at least one fluid column defined therein selected as a communication channel which extends between a first communication node and a second communication node, comprising:

a transducer, located at said first communication node, in force-transferring communication with said communication channel;

a housing for securing said transducer to a selected one of said concentrically nested tubular strings, with said housing extending into, and partially obstructing, said annular region;

a reflection member positioned relative to said housing so that said transducer is intermediate (a) said communication channel and (b) said reflection member; and

said reflection member being dimensioned in (1) cross-sectional area, and (2) length with respect to at least one of (1) said communication channel, (2) said housing, and (3) a probable acoustic communication frequency to reflect acoustic energy into said communication channel between said first and second communication nodes.

9. An acoustic communication apparatus according to claim 8:

wherein said reflection member extends into, and partially obstructs, said annular region, but to a lesser extent than said housing.

10. An acoustic communication apparatus according to claim 8:

wherein said reflection member partially obstructs said annular region to provide a surrounding annular region with a cross-sectional area approximately equal to the cross-sectional area of said communication channel.

11. An acoustic communication apparatus according to claim 8:

wherein said reflection member is spaced from said housing a distance approximately equal to one-quarter wavelength of said probable acoustic communication frequency; and

wherein said reflection member has a length approximately equal to one-quarter wavelength of said probable acoustic communication frequency.

12. An acoustic communication apparatus according to claim 11:

wherein said reflection member defines;

(a) a multiple number of step increases in cross-sectional area in said wellbore, spaced from said transducer generally an odd number of quarter wavelengths about said probable acoustic communication frequency, said step increases being positioned lengthwise in said wellbore in a direction from said transducer opposite that of desired communication; and

(b) a multiple number of step decreases in the liquid cross-sectional area in said wellbore, interleaved with said step increases, and spaced from said transducer generally an even number of quarter wavelengths of said probable acoustic communication frequency.

13. An acoustic communication apparatus for use in a wellbore having a plurality of concentrically nested tubular strings disposed therein, with a selected fluid column therein selected as a communication channel for acoustic communication between a first communication node and a second communication node, comprising:

an actuator member for selected bidirectional conversion of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation; and

a housing for securing said actuator member in a selected location within said wellbore, said housing extending into, and partially obstructing, said annular region, so that said annular region surrounding said housing has a cross-sectional area which is less than that of said communication channel.

14. An acoustic communication apparatus according to claim 13, further comprising:

an impedance matching member for minimizing reflection of acoustic energy at said housing.

15. An acoustic communication apparatus according to claim 13, further comprising:

a reflection member for reflecting acoustic energy into said communication channel.

16. An acoustic communication apparatus according to claim 13, further comprising:

a fluid body located within said housing, and communicating with said communication channel, for preferentially directing acoustic energy into said communication channel to reinforce acoustic communication.

17. In borehole communication, a method of communicating data between two locations using travel of acoustic waves in a borehole liquid without modifying or requiring liquid flow, comprising the steps of:

(a) characterizing an acoustic channel created by said liquid in said borehole by;

(1) generating a characterizing signal at one of said locations;

(2) transmitting said characterizing signal via said borehole liquid to the other of said locations; and

(3) analyzing said characterizing signal after it is received at said second location to select a frequency band having a channel capacity adequate for the desired communication;

(b) generating an acoustic signal having a frequency in said frequency band, which signal defines said data;

(c) coupling said acoustic signal to a borehole liquid in a first portion thereof positioned at a first one of said locations;

(d) receiving said acoustic signal from a second portion of said borehole liquid at the second one of said locations; and

thereafter

(e) recovering said data from said acoustic signal.

18. The method of claim 17 wherein at least a part of said communication is within a borehole within which an annulus is defined for borehole liquid, and at least one of said portions is within said annulus.

19. The method of claim 17 wherein said acoustic signal is a signal which is modulated with said data.

20. The method of claim 17 further including the steps of:

(f) generating a second acoustic signal having a frequency in said frequency band, which second signal defines data;

(g) coupling said second acoustic signal to said borehole liquid in said second portion thereof positioned at said second one of said locations;

(h) receiving said second acoustic signal from said second portion of said borehole liquid at the first one of said locations; and

thereafter

(i) recovering said data from said second acoustic signal.

21. The method of claim 17 wherein said analyzing step includes performing a fast Fourier transform upon said characterizing signal.

22. The method of claim 17 wherein said analyzing step includes:

determining a signal to noise ratio for said characterizing signal within a specified frequency band;

determining a bandwidth of constant signal to noise ratio within said specified frequency band; and

choosing a frequency within said specified frequency band having a best signal to noise ratio and an acceptable bandwidth therearound as said best transmission frequency.

23. In borehole communication, a method of communicating data between two locations using travel of acoustic waves in a transmission medium extending in said borehole, comprising the steps of:

(a) generating a first synchronizing signal in a first transceiver at one of said locations;

(b) acoustically transmitting said first synchronizing signal via said transmission medium to a second transceiver at the other of said locations;

(c) receiving said synchronizing signal at said second transceiver;

(d) synchronizing said second transceiver with said first transceiver based upon the received synchronizing signal;

(e) generating a second synchronizing signal in said second transceiver;

(f) acoustically transmitting said second synchronizing signal via said transmission medium to said second transceiver;

(g) receiving said second synchronizing signal at said second transceiver; and

(h) synchronizing said first transceiver with said second transceiver based upon the received second synchronizing signal.

24. The method of claim 23 wherein said first synchronizing signal is a chirp signal.

25. The method of claim 23 wherein said second synchronizing signal is comprised of two tones.

26. The method of claim 25 further including the steps of:

(i) performing a fast Fourier transform on each tone;

(j) determining a phase difference between each fast Fourier transform of each tone;

(k) generating a time adjustment from said phase difference; and

(l) adjusting a clock of said first transceiver by said time adjustment.

27. In borehole communication, a method of communicating data between two locations using travel of acoustic waves in a borehole liquid for such communication, comprising the steps of:

(a) synchronizing a first transceiver at one of said locations with a second transceiver at the other of said locations by;

(1) generating a synchronizing signal in said first transceiver;

(2) acoustically transmitting said synchronizing signal via said borehole liquid to said second transceiver;

(3) receiving said synchronizing signal at said second transceiver;

(4) approximately synchronizing said second transceiver with said first transceiver based upon the received synchronizing signal;

(5) generating a second synchronizing signal in said second transceiver;

(6) acoustically transmitting said second synchronizing signal via said borehole liquid to said second transceiver;

(7) receiving said second synchronizing signal at said second transceiver;

(8) synchronizing said first transceiver with said second transceiver based upon the received second synchronizing signal;

(b) modulating a first electrical signal with a data signal for said first transceiver;

(c) generating a modulated acoustic signal from said first electrical signal after the latter is modulated;

(d) coupling said modulated acoustic signal with said first transceiver to a first portion of borehole liquid located at said first transceiver;

(e) thereafter receiving said modulated acoustic signal with said second transceiver from a second portion of said borehole liquid;

(f) converting said received modulated acoustic signal to a second electrical signal defining said data; and

(g) recovering said data from said second electrical signal.

28. The method of claim 27 wherein said first synchronizing signal is a chirp signal.

29. The method of claim 27 wherein said second synchronizing signal is comprised of two tones.

30. The method of claim 29 wherein said step of receiving said second synchronizing signal includes:

performing a fast Fourier transform on each tone;

determining a phase difference between each fast Fourier transform of each tone;

generating a time adjustment from said phase difference; and

adjusting a clock of said first transceiver by said time adjustment.

36. The method of claim 30 wherein said first data signal is a command signal and said second data signal is a sensor signal and a command acknowledgement signal.

37. The method of claim 30 wherein said transmission medium is borehole liquid.

31. In borehole communication, a method of communicating data between two locations using travel of acoustic waves in a transmission medium extending in said borehole without the transmission medium itself having to travel between such locations for such communication, comprising the steps of:

(a) characterizing an acoustic channel created by said transmission medium by;

(1) generating a characterizing signal at a first one of said locations;

(2) acoustically transmitting said characterizing signal via said transmission medium to a second one of said locations;

(3) receiving said characterizing signal at said second location;

(4) analyzing said received characterizing signal;

(5) determining a best transmission frequency for communicating from one of said first locations to the other based upon said analyzed signal;

(b) synchronizing a first transceiver at one of said locations with a second transceiver at the other of said locations;

(c) modulating a first electrical signal with a data signal for said first transceiver;

(d) generating a modulated acoustic signal from said first electrical signal after the latter is modulated;

(e) coupling said modulated acoustic signal with said first transceiver to a first portion of said transmission medium located at said first transceiver;

(f) thereafter receiving said modulated acoustic signal with said second transceiver from a second portion of said transmission medium;

(g) converting said received modulated acoustic signal to a second electrical signal defining said data; and

(h) recovering said data from said second electrical signal.

32. The method of claim 31 wherein said step of receiving said characterizing signal includes performing a fast Fourier transform upon said characterizing signal.

33. The method of claim 31 wherein said characterizing signal is a chirp signal.

34. The method of claim 31 wherein said step of analyzing said received characterizing signal includes:

determining a signal to noise ratio for said characterizing signal within a specified frequency band;

determining a bandwidth of acceptable signal-to-noise ratio within said specified frequency band;

choosing a center frequency within said bandwidth as said transmission frequency.

35. A method of bi-directionally communicating information and control data using acoustic waves between a downhole acoustic transceiver contained in a downhole carrier incorporated into a drillstring and a surface acoustic transceiver, said method comprising the steps of:

(a) generating a characterizing signal in a first transceiver for characterizing an acoustic channel created by a transmission medium in said borehole;

(b) acoustically transmitting said characterizing signal via said transmission medium to a second transceiver;

(c) receiving said characterizing signal with said second transceiver;

(d) analyzing said received characterizing signal;

(e) determining a best transmission frequency for communicating from said first transceiver to said second transceiver via transmission medium;

(f) generating a first synchronizing signal in said first transceiver;

(g) acoustically transmitting said first synchronizing signal via said borehole liquid to said second transceiver;

(h) receiving said first synchronizing signal at said second transceiver;

(i) synchronizing said second transceiver with said first transceiver based upon the received first synchronizing signal;

(j) generating a second synchronizing signal in said second transceiver;

(k) acoustically transmitting said second synchronizing signal via said transmission medium to said second transceiver;

(l) receiving said second synchronizing signal at said second transceiver;

(m) synchronizing said first transceiver with said second transceiver based upon the received second synchronizing signal;

(n) modulating a first electrical signal with a first data signal within said first transceiver;

(o) generating a first modulated acoustic signal from said first electrical signal;

(p) coupling said first modulated acoustic signal to said transmission medium;

(q) receiving said first modulated acoustic signal with said second transceiver;

(r) converting said received modulated acoustic signal to a second electrical signal;

(s) recovering said first data signal from said second electrical signal;

(t) modulating a third electrical signal with a second data signal within said second transceiver;

(u) generating a second modulated acoustic signal from said third electrical signal;

(v) coupling said second modulated acoustic signal to said transmission medium;

(w) receiving said second modulated acoustic signal with said first transceiver;

(x) converting said received second modulated acoustic signal to a fourth electrical signal; and

(y) recovering said second data signal from said fourth electrical signal.

38. A method of transmitting data in a wellbore between a first transceiver at a first communication node and a second transceiver at a second communication node through a communication channel defined in a wellbore component, comprising:

generating a characterizing signal at a selected one of said first and second communication nodes;

said characterizing signal including a plurality of signal components, each having a selected frequency, with said plurality of signal components spanning a preselected range of frequencies;

applying said characterizing signal to said communication channel;

receiving said characterizing signal with a selected one of said first and second transceivers;

analyzing said characterizing signal to identify portions of said preselected range of frequencies which are suitable for communicating data between said first and second communication nodes at that particular time; and

communicating data in said communication channel in at least one selected portion of said preselected range of frequencies.

39. A method of transmitting data according to claim 38, wherein said wellbore component which defines said communication channel comprises a fluid column.

40. A method of transmitting data according to claim 38, wherein said wellbore component which defines said communication channel comprises a wellbore tubular string.

41. A method of transmitting data according to claim 38, further comprising:

continuously generating, applying, receiving, and analyzing said characterizing signal to identify portions of said preselected range of frequencies which are suitable for communicating data between said first and second communication nodes at subsequent times; and

communicating data in said communication channel in at least one selected portion of said preselected range of frequencies.

42. A method of transmitting data according to claim 38, further comprising:

during said step of communicating data, automatically and periodically generating, applying, receiving, and analyzing said characterizing signal to identify portions of said preselected range of frequencies which are suitable for communicating data between said first and second communication nodes; and

switching between selected portions of said preselected range of frequencies to optimize communication of data between said first and second communication nodes.

43. A method of transmitting data according to claim 38:

wherein, during said step of generating, said characterizing signal is generated utilizing a selected one of said first and second transceivers.

44. A method of transmitting data according to claim 38:

wherein a plurality of characterizing signals are generated at selected ones of said first and second communication nodes, with each being analyzed to identify portions of said preselected range of frequencies which are suitable for communicating data in a particular direction between said first and second communication nodes.

45. A method of transmitting data according to claim 38:

wherein said step of analyzing includes identifying at least one portion of said preselected range of frequencies which have an adequate bandwidth for communication of data.

46. A method of transmitting data according to claim 38:

wherein said step of analyzing includes identifying at least one portion of said preselected range of frequencies which have an adequate signal to noise characteristic for communication of data.

47. A method of transmitting data according to claim 38:

wherein said step of analyzing includes performing frequency-domain analysis of the received characterizing signal.

48. A method according to claim 38:

wherein said step of analyzing includes creating a histogram utilizing preselected frequency bins.

49. A method of transmitting data according to claim 38:

wherein said step of analyzing includes comparison of coherent running totals to incoherent running totals.

50. A method of transmitting data according to claim 38, further comprising:

synchronizing operation of said first and second transceivers.

51. A method of transmitting data according to claim 38, further comprising:

subsequent to said step of analyzing, transmitting data between said first and second transceivers which identifies at least a center frequency for at least one selected portion of said preselected range of frequencies.

52. A method of transmitting data according to claim 38:

wherein said communication channel comprises a dynamic fluid column in said wellbore; and

wherein said method steps of claim 38 continually performed to optimize data communication in said dynamic fluid column.

53. A method of transmitting data according to claim 38:

wherein said communication channel comprises a dynamic fluid column in said wellbore;

wherein mechanical changes affect acoustic transmission properties of said communication channel; and

wherein said steps of claim 38 are performed to automatically optimize data communication in said dynamic fluid column, notwithstanding said mechanical changes.

54. An acoustic communication apparatus for use in a wellbore with a selected fluid column therein selected as a communication channel for acoustic communication between a first communication node and a second communication node, comprising:

a first actuator member for conversion of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

a second actuator member for conversion of at least one of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

housings for securing said first and second actuator members in selected locations within said wellbore; and

wherein said acoustic communication apparatus is operable in a plurality of modes of operation including at least;

(a) a communication channel characterization mode of operation wherein a characterization signal is transmitted in said communication channel and then analyzed to identify at least one communication frequency for optimal communication; and

(b) a data communication mode of operation, wherein data is transmitted between said first and second communication nodes through operation of said first and second actuator members at said at least one communication frequency.

55. An acoustic communication apparatus according to claim 54:

wherein said acoustic communication apparatus is utilized to communicate data within said wellbore during drilling operations.

56. An acoustic communication apparatus according to claim 54:

wherein said acoustic communication apparatus is utilized to communicate data in said wellbore during completion operations.

57. An acoustic communication apparatus according to claim 54:

wherein said acoustic communication apparatus is utilized to communicate data in said wellbore during production operations.

58. An acoustic communication apparatus for use during drilling operations in a wellbore having a drillstring disposed therein composed of a drill pipe section and a drill collar section, with a selected fluid column within said wellbore selected as a communication channel for acoustic communication between a first communication node and a second communication node, comprising:

a first actuator member located at said first communication node for conversion of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

a second actuator member located at said second communication node for conversion of at least one of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

housings for securing said first and second actuator members in selected locations within said wellbore; and

wherein said acoustic communication apparatus is operable in a plurality of modes of operation including at least;

(a) a communication channel characterization mode of operation wherein a characterization signal is transmitted in said communication channel and then analyzed to identify at least one communication frequency for optimal communication; and

(b) a data communication mode of operation, wherein data is transmitted between said first and second communication nodes through operation of said first and second actuator members at said at least one communication frequency.

59. An acoustic communication apparatus according to claim 58:

wherein said first communication node is located in said drill collar section of said drillstring;

wherein said second communication node is located in said drillstring upward from said first communication node;

wherein said first actuator member is utilized to transmit data pertaining to at least one of (a) drillstring operations, (b) wellbore conditions, and (c) formation conditions to said second actuator member.

60. An acoustic communication apparatus according to claim 59:

wherein said data received by said second actuator member is supplied to a measurement-while-drilling data transmission system for at least one of (a) processing and (b) retransmission.

61. An acoustic communication apparatus according to claim 59:

wherein said second communication node is located at a wellhead for said wellbore; and

wherein said first actuator member is utilized to transmit data to said wellhead.

62. An acoustic communication apparatus according to claim 61:

wherein said first actuator member is utilized to transmit data to said wellhead in parallel with a measurement-while-drilling data transmission system.

63. An acoustic communication apparatus according to claim 58:

wherein said first communication node is located in said drill collar section of said drillstring adjacent a drill bit;

wherein said second communication node is located in said drill collar section of said drillstring above said first communication node, adjacent a measurement-while-drilling data transmission system; and

wherein data pertaining to near-drillbit conditions is transmitted from said first communication node to said second communication node.

64. A method of detecting influx of gas into a fluid column in a wellbore therein which defines a communication channel, comprising:

providing at least one actuator for conversion of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

utilizing said at least one actuator for generating an interrogating signal at a selected location within said wellbore;

applying said interrogating signal to said communication channel;

receiving said interrogating signal with said at least one actuator;

analyzing said interrogating signal to identify at least one of;

(a) portions of a preselected range of frequencies which are suitable for communicating data in said wellbore at that particular time;

(b) communication channel attributes; and

(c) signal attributes;

repeating said steps of utilizing, applying, receiving, and analyzing to identify changes in at least one of;

(a) portions of said preselected range of frequencies which are suitable for communicating data in said wellbore;

(b) communication channel attributes; and

(c) signal attributes;

which, correspond to a likely influx of gas into said fluid column in said wellbore.

65. A method according to claim 64:

wherein said portions of said preselected range of frequencies which are suitable for communicating data in said wellbore are identified by at least one of (a) frequency, (b) bandwidth, (c) a signal-to-noise characteristic, (d) signal amplitude, and (e) signal time delay.

66. A method according to claim 64:

wherein said communication channel attributes include at least one of;

(a) communication channel length; and

(b) communication channel impedance.

67. A method according to claim 64:

wherein said signal attributes include at least one of;

(a) signal amplitude;

(b) signal phase;

(c) loss of signal in the selected portion of the preselected range of frequencies of the communication channel; and

(d) signal time delay.

68. A method according to claim 64:

wherein said at least one actuator comprises a single actuator; and

wherein said interrogating signal received by said single actuator is an echo signal in said communication channel.

69. A method according to claim 64:

wherein said at least one actuator comprises a first actuator disposed at a first wellbore location and a second actuator disposed at a second wellbore location; and

wherein said interrogating signal is transmitted between said first and second actuators.

70. A method according to claim 64, further comprising:

providing a reflection marker and coupling it to a wellbore tubular; and

reflecting said interrogating signal off of said reflection marker.

71. An acoustic communication apparatus for use in a wellbore with a selected wellbore component therein selected as a communication channel for acoustic communication between a first communication node and a second communication node, comprising:

a first actuator member for conversion of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

a second actuator member for conversion of at least one of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

housings for securing said first and second actuator members in selected locations within said wellbore; and

wherein during a data communication mode of operation;

(a) a binary "one" is transmitted through said communication channel by utilizing a selected one of said first and second actuator members to generate an acoustic signal with a plurality of signal components, said signal components spanning a first preselected range of frequencies; and

(b) a binary "zero" is transmitted through said communication channel by utilizing a selected one of said first and second actuator members to generate an acoustic signal with a plurality of signal components, said signal components spanning a second preselected range of frequencies, different from that range of frequencies for said binary "one".

72. An acoustic communication apparatus according to claim 71:

wherein said communication channel comprises a fluid column defined within said borehole.

73. An acoustic communication apparatus according to claim 71 wherein, during said data communication mode of operation:

(a) said binary "one" is detected by a selected one of said first and second actuator members by examining energy levels within said first preselected range of frequencies; and

(b) said binary "zero" is detected by a selected one of said first and second actuator members by examining energy levels with said second preselected range of frequencies.

74. An acoustic communication apparatus according to claim 73:

wherein said energy levels for said first preselected range of frequencies is compared to a baseline energy level for said first preselected range of frequencies; and

wherein said energy levels for said second preselected range of frequencies is compared to a baseline energy level for said second preselected range of frequencies.

75. A method of detecting at least one of (a) a fluid influx and (b) a gas influx into a fluid column in a wellbore therein which defines a communication channel, comprising:

providing at least one actuator for conversion of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

utilizing said at least one actuator for generating an interrogating signal at a selected location within said wellbore;

applying said interrogating signal to said communication channel;

receiving said interrogating signal with said at least one actuator;

analyzing said interrogating signal to identify at least one of;

(a) portions of a preselected range of frequencies which are suitable for communicating data in said wellbore at that particular time;

(b) communication channel attributes; and

(c) signal attributes;

repeating said steps of utilizing, applying, receiving, and analyzing to identify changes in at least one of;

(a) portions of said preselected range of frequencies which are suitable for communicating data in said wellbore;

(b) communication channel attributes; and

(c) signal attributes;

which, correspond to a likely occurrence of at least one of (a) fluid influx and (b) gas influx into said fluid column in said wellbore.

76. A method according to claim 75:

wherein said portions of said preselected range of frequencies which are suitable for communicating data in said wellbore are identified by at least one of (a) frequency, (b) band width, (c) a signal-to-noise characteristic, (d) signal amplitude, and (e) signal time delay.

77. A method according to claim 75:

wherein said communication channel attributes include at least one of;

(a) communication channel length;

(b) communication channel impedance;

(c) frequency band width; and

(d) phase shift.

78. A method according to claim 75:

wherein said signal attributes include at least one of;

(a) signal amplitude;

(b) signal phase;

(c) loss of signal;

(d) signal time delay;

(e) frequency response; and

(f) acoustic spectral density.

79. A method according to claim 75:

wherein said at least one actuator comprises a single actuator; and

wherein said interrogating signal received by said single actuator is an echo signal in said communication channel.

80. A method according to claim 75:

wherein said at least one actuator comprises a first actuator disposed at a first wellbore location and a second actuator disposed at a second wellbore location; and

wherein said interrogating signal is transmitted between said first and second actuators.

81. A method according to claim 75, further comprising:

providing a reflection marker and coupling it to a wellbore tubular; and

reflecting said interrogating signal off of said reflection marker.

82. A method of detecting at least one of (a) fluid influx, and (b) gas influx into a fluid column in a wellbore therein which defines a communication channel, comprising:

providing at least one actuator for conversion of at least one of (a) a provided coded electrical signal to a corresponding generated coded acoustic signal during a message transmission mode of operation, and (b) a provided coded acoustic signal to a corresponding generated coded electrical signal during a message reception mode of operation;

utilizing said at least one actuator for generating an interrogating signal at a selected location within said wellbore;

applying said interrogating signal to said communication channel;

receiving said interrogating signal with said at least one actuator;

analyzing said interrogating signal to identify at least one of;

(a) portions of a preselected range of frequencies which are suitable for communicating data in said wellbore at that particular time;

(b) communication channel attributes; and

(c) signal attributes;

repeating said steps of utilizing, applying, receiving, and analyzing to identify changes in at least one of;

(a) portions of said preselected range of frequencies which are suitable for communicating data in said wellbore;

(b) communication channel attributes; and

(c) signal attributes;

which, correspond to at least one of a likely (a) fluid influx, and (b) gas influx, into said fluid column in said wellbore; and

displaying information which is sufficient to allow a human operator to detect and monitor at least one of a likely (a) fluid influx, and (b) gas influx.

83. A method according to claim 82:

wherein said portions of said preselected range of frequencies which are suitable for communicating data in said wellbore are identified by at least one of (a) frequency, (b) band width, (c) a signal-to-noise characteristic, (d) signal amplitude, and (e) signal time delay.

84. A method according to claim 82 wherein during said step of displaying, at least one of the following communication channel attributes is displayed:

(a) communication channel length;

(b) communication channel impedance;

(c) frequency band width; and

(d) phase shift.

85. A method according to claim 82 wherein during said step of displaying, at least one of the following signal attributes is displayed:

(a) signal amplitude;

(b) signal phase;

(c) loss of signal;

(d) signal time delay;

(e) frequency response; and

(f) acoustic spectral density.

86. A method according to claim 82:

wherein said at least one actuator comprises a single actuator; and

wherein said interrogating signal received by said single actuator is an echo signal in said communication channel.

87. A method according to claim 82:

wherein said at least one actuator comprises a first actuator disposed at a first wellbore location and a second actuator disposed at a second wellbore location; and

wherein said interrogating signal is transmitted between said first and second actuators.

88. A method according to claim 82, further comprising:

providing a reflection marker and coupling it to a wellbore tubular; and

reflecting said interrogating signal off of said reflection marker.