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United States Patent Application	20040065437
Kind Code	A1
Bostick,, Francis X. III ;   et al.	April 8, 2004

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Claims

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What is claimed is:

1. An apparatus deployable down a well having a casing with an inner diameter, comprising: a mandrel containing a first tube coupleable to a production tube, the mandrel having an outside diameter; and at least one fiber-optic-based seismic sensor housed within the mandrel.

2. The apparatus of claim 1, wherein the mandrel is round in cross section.

3. The apparatus of claim 1, wherein the mandrel is polygonal in cross section.

4. The apparatus of claim 1, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.

5. The apparatus of claim 1, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.

6. The apparatus of claim 5, further comprising a means for holding the sensor within the groove.

7. The apparatus of claim 1, wherein the sensor is housed within a tunnel formed within the mandrel.

8. The apparatus of claim 1, wherein the mandrel contains a plurality of channels.

9. The apparatus of claim 1, wherein the sensor comprises three seismic sensors oriented orthogonally with respect to each other.

10. The apparatus of claim 1, wherein the first tube is not concentric within the mandrel.

11. The apparatus of claim 1, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.

12. The apparatus of claim 1, further comprising a production tube coupled to the first tube, and further comprising a displacement device coupled to the production tube.

13. The apparatus of claim 1, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.

14. An apparatus deployable down a well having a casing with an inner diameter, comprising: a mandrel containing a tube coupleable to a production tube, the mandrel having an outside diameter slightly less than that of the inner diameter of the casing such that the mandrel is capable of directly contacting the casing by natural forces; and at least one sensor housed within the mandrel.

15. The apparatus of claim 14, wherein the mandrel is round in cross section.

16. The apparatus of claim 14, wherein the mandrel is polygonal in cross section.

17. The apparatus of claim 14, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.

18. The apparatus of claim 14, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.

19. The apparatus of claim 18, further comprising a means for holding the sensor within the groove.

20. The apparatus of claim 14, wherein the sensor is housed within a tunnel formed within the mandrel.

21. The apparatus of claim 14, wherein the at least one sensor comprises at least one seismic sensor.

22. The apparatus of claim 21, wherein there are three seismic sensors oriented orthogonally with respect to each other.

23. The apparatus of claim 14, wherein the first tube is not concentric within the mandrel.

24. The apparatus of claim 14, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.

25. The apparatus of claim 14, further comprising a production tube coupled to the first tube, and further comprising a displacement device coupled to the production tube.

26. The apparatus of claim 14, wherein the sensor comprises an optical sensor.

27. An apparatus deployable down a well having a casing with an inner diameter, comprising: a mandrel containing a first tube coupleable to a production tube, the mandrel having an outside diameter; and at least one sensor housed within a groove in the mandrel, wherein the first tube is not concentric within the mandrel.

28. The apparatus of claim 27, wherein the mandrel is round in cross section.

29. The apparatus of claim 27, wherein the mandrel is polygonal in cross section.

30. The apparatus of claim 27, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.

31. The apparatus of claim 27, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.

32. The apparatus of claim 31, further comprising a means for holding the sensor within the groove.

33. The apparatus of claim 27, wherein the sensor is housed within a tunnel formed within the mandrel.

34. The apparatus of claim 27, wherein the at least one sensor comprises at least one seismic sensor.

35. The apparatus of claim 34, wherein there are three seismic sensors oriented orthogonally with respect to each other.

36. The apparatus of claim 27, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.

37. The apparatus of claim 27, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.

38. The apparatus of claim 27, further comprising a production tube coupled to the first tube, and further comprising a displacement device coupled to the production tube.

39. The apparatus of claim 27, wherein the sensor comprises an optical sensor.

40. A system for taking measurements in a well, comprising: a well comprising a casing having an inner diameter; a production tube disposed in the well; at least one mandrel coupled to the production tube, the mandrel having an outside diameter; and at least one sensor apparatus housed within the mandrel, wherein the mandrel is in contact with the casing.

41. The system of claim 40, wherein the mandrel is round in cross section.

42. The system of claim 40, wherein the mandrel is polygonal in cross section.

43. The system of claim 40, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.

44. The system of claim 40, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.

45. The system of claim 44, further comprising a means for holding the sensor within the groove.

46. The system of claim 40, wherein the sensor is housed within a tunnel formed within the mandrel.

47. The system of claim 40, wherein the at least one sensor comprises at least one seismic sensor.

48. The system of claim 47, wherein there are three seismic sensors oriented orthogonally with respect to each other.

49. The system of claim 40, further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.

50. The system of claim 40, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.

51. The system of claim 40, wherein the mandrel contains a first tube coupled to the production tube, and wherein the first tube is not concentric within the mandrel.

52. The system of claim 40, further comprising a displacement device coupled to the production tube.

53. The system of claim 52, wherein the displacement device has a radial protrusion away from an axis of the production tube which is larger than the difference between one-half of the inside diameter of the casing and one-half the outside diameter of the production tube.

54. The system of claim 52, wherein the displacement device touches the casing to displace the production device from the axis of the casing.

55. The system of claim 40, wherein the sensor comprises an optical sensor.

56. The system of claim 40, wherein the well is deviated, non-linear, or non-vertical.

57. The system of claim 56, wherein the mandrel is in contact with the casing at a point of deviation, non-linearity, or non-verticality in the well.

58. A method for deploying an apparatus capable of taking seismic measurements, comprising: deploying a production tube down a well containing a casing with an inner diameter, wherein the production tube comprises at least one mandrel with an outside diameter which houses at least one sensor; and contacting the mandrel and the casing by natural forces.

59. The method of claim 58, wherein the mandrel is round in cross section.

60. The method of claim 58, wherein the mandrel is polygonal in cross section.

61. The method of claim 58, wherein the mandrel contains a plurality of protrusions extending radially from the mandrel.

62. The method of claim 58, wherein the sensor is housed within a groove formed in an outside surface of the mandrel.

63. The method of claim 62, further comprising a means for holding the sensor within the groove.

64. The method of claim 58, wherein the sensor is housed within a tunnel formed within the mandrel.

65. The method of claim 58, wherein the at least one sensor comprises at least one seismic sensor.

66. The method of claim 65, wherein there are three seismic sensors oriented orthogonally with respect to each other.

67. The method of claim 58, wherein the mandrel further comprising at least one channel formed on an outside surface of the mandrel to allow the passage of materials between the mandrel and the casing.

68. The method of claim 58, wherein the outside diameter of the mandrel is slightly less than that of the inner diameter of the casing.

69. The method of claim 58, wherein the mandrel contains a first tube coupled to the production tube, and wherein the first tube is not concentric within the mandrel.

70. The method of claim 58, wherein contacting the mandrel and the casing by natural forces comprises the use of a displacement device coupled to the production tube.

71. The method of claim 70, wherein the displacement device has a radial protrusion away from an axis of the production tube which is larger than the difference between one-half of the inside diameter of the casing and one-half the outside diameter of the production tube.

72. The method of claim 70, wherein the displacement device touches the casing to displace the production device from the axis of the casing.

73. The method of claim 58, wherein the sensor comprises an optical sensor.

74. The method of claim 58, wherein the well is deviated, non-linear, or non-vertical.

75. The method of claim 58, wherein contacting the mandrel and the casing by natural forces comprises contact between the mandrel and the casing at a point of deviation in the well.

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Description

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CROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This application is filed concurrently with U.S. Patent Application having Express Mail No. EL830942248US, Attorney Docket No. 13137.0167.NPUS00, entitled "Multiple Component Sensor Mechanism," U.S. Provisional Patent Application having Express Mail No. EL830942251US, Attorney Docket No. 13137.0131.NPUS00, entitled "Clamp Mechanism for In-Well Seismic Sensor," and U.S. Patent Application having Express Mail No. EL830942234US, Attorney Docket No. 13137.0166.NPUS00, entitled "Apparatus and Method or Transporting, Deploying, and Retrieving Arrays Having Nodes Interconnected by Sections of Cable," which contain related subject matter and are incorporated herein by reference in their entireties.

FIELD OF THE INVENTION

[0002] This invention relates generally to seismic sensing, and more particularly to seismic surveying of an earth formation in, particularly, a deviated, non-linear, or non-vertical bore hole.

BACKGROUND OF THE INVENTION

[0003] Seismic surveying is a standard tool for the exploration of hydrocarbon reservoirs. As is known, seismology involves the detection acoustic waves to determine the strata of geologic features, and hence the probable location of oil and/or gas.

[0004] Various types of acoustic and/or pressure sensors used in seismology are well known. While seismic sensors can be placed on land, or on the bottom or surface of the ocean, such sensors may also be placed within the borehole of the well itself. This approach is generally known as borehole seismology or vertical seismic profiling (VSP) because the sensors are usually arranged substantially vertically within the borehole of the well. Borehole seismology may occur within a single well, or may be used in multiple wells, i.e., a cross-well arrangement, as is well known.

[0005] Borehole seismology however is generally somewhat difficult and costly to perform. According to some prior art borehole seismology approaches, sensors are only temporarily located within the borehole. During this temporary placement, the sensors may be used to take readings, and then must be retrieved from the borehole. While the measurements are made, production from the well, if any, might need to be halted, which can be disruptive and costly, particularly if measurements are periodically made to assess strata conditions over a given time period. Accordingly, because of the time, costs, and hassles involved with temporary displacement of sensors, it is generally preferred to permanently position the sensors within the borehole, and further preferred that such sensing not substantially interfere with normal production operations.

[0006] Moreover, it is beneficial to mechanically couple certain seismic sensors to the borehole, including displacement sensors, geophones, and accelerometers, and hence the earth formation of interest. This is because the acoustic waves used in seismic analysis will more easily travel to these sensors without attenuation (coupling through liquids or gases will cause signal attenuation), and because different types of particle motion (e.g., shear waves) can be sensed, which is not possible when coupling occurs only through a liquid or gas. However, one must go to some effort to affirmatively couple the sensors to the borehole structure, usually by active means that can be costly and complex.

[0007] It would be beneficial therefore to deploy a sensor down in borehole in a manner that would naturally (i.e., passively) couple itself to the borehole, i.e., that would couple without further intervention by the production engineer. It would further be beneficial for such a deployment to be suitable for use within deviated (i.e., curved, non-vertical, non-straight) wells, as prior art techniques may experience problems in dealing with such wells. For example, in deviated, non-linear, or non-vertical wells, sensing apparatuses may stick, break, or become dislodged in such wells.

[0008] The following references, which disclose subject matters to those related herein, may be useful to further understand the technology at issue, and/or its shortcomings, and are hereby incorporated by reference in their entireties: U.S. Pat. Nos. 6,072,567; 6,016,702; 5,361,130; 5,401,956; 5,493,390; 5,925,879; 5,767,411; PCT Publication No. WO 02/04984.

SUMMARY OF THE INVENTION

[0009] A mandrel housing for permanently deploying a seismic sensor or sensor apparatus down a well is disclosed. The mandrel is formed integral with or attached to a pipe and is incorporatable into the production piping string. The outer diameter of the mandrel is designed to be slightly smaller than the inside diameter of the well casing which allows the mandrel to naturally come into contact with the well casing at points of deviation, non-linearity, or non-verticality in the casing. This mechanical coupling of the mandrel to the well casing, and hence the earth formation, improves the resolution and type of seismic signals to be detected by the sensor apparatus. The sensor apparatus fits into a groove on the mandrel and is preferably clamped or welded into place or placed within a tunnel formed in the mandrel. The mandrel further preferably contains channels on its side to allow materials within the annulus to flow around the mandrel even when the mandrel is in contact with the casing.

BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The foregoing and other features and aspects of the present disclosure will be best understood with reference to the following detailed description of embodiments of the invention, when read in conjunction with the accompanying drawings, wherein:

[0011] FIG. 1 illustrates the placement of production tubing in a deviated well bore.

[0012] FIG. 2 illustrates models to estimate the effects of torque and drag.

[0013] FIG. 3 illustrates an embodiment of the disclosed mandrel deployed in a well bore and in contact with the well bore casing.

[0014] FIG. 4 illustrates an embodiment of the disclosed mandrel and the sensor apparatus attached to the mandrel.

[0015] FIG. 5 illustrates an exemplary method by which the sensor apparatus can be affixed to the mandrel.

[0016] FIG. 6A illustrates a cross-sectional view of the mandrel embodiment of FIG. 4.

[0017] FIG. 6B illustrates a cross-section view of the mandrel in which the production pipe is not concentric with the outside diameter of the mandrel.

[0018] FIG. 7 illustrates another exemplary method by which the sensor apparatus can be affixed to the mandrel.

[0019] FIG. 8 illustrates another exemplary method by which the sensor apparatus can be affixed to the mandrel.

[0020] FIG. 9 illustrates a cross-sectional view of an elliptical mandrel embodiment.

[0021] FIG. 10 illustrates another exemplary method by which the sensor apparatus can be affixed to the mandrel using a tunnel.

[0022] FIG. 11 illustrates a cross-sectional view of a mandrel having a polygonal shape.

[0023] FIG. 12 illustrates a cross-section view of a mandrel having protrusions.

[0024] FIG. 13 illustrates a displacement device coupled to a production pipe to facilitate contact between the disclosed mandrel and the casing.

DETAILED DESCRIPTION OF EMBODIMENTS OF THE INVENTION

[0025] In the disclosure that follows, in the interest of clarity, not all features of actual implementations of a seismic sensing mandrel are described in this disclosure. It will of course be appreciated that in the development of any such actual implementation, as in any such project, numerous engineering and design decisions must be made to achieve the developers' specific goals, e.g., compliance with mechanical and business related constraints, which will vary from one implementation to another. While attention must necessarily be paid to proper engineering and design practices for the environment in question, it should be appreciated that the development of a seismic sensing mandrel would nevertheless be a routine undertaking for those of skill in the art given the details provided by this disclosure, even if such development efforts are complex and time-consuming.

[0026] The disclosed embodiments are particularly useful in seismic surveying using deviated wells, such as extended reach wells, and horizontal well bores, although it will also have application in wells exhibiting any degree of non-linearity or slant (as most well do) or even in near-perfectly vertical wells. Deviated, non-linear, or non-vertical wells present torque or drag related problems during drilling because the drill string contacts the low side of the casing of the borehole. In the same way, torque and drag phenomenon also occurs with respect to deployment of a production tube. This is shown generally in FIG. 1, which shows a production tube 1 in contact with a well casing 2 at certain contact points 3 as induced by the gravitation influence on the tube 1 and its amount of flexure within the casing. The casing 2 can be suitably acoustically coupled to the earth formation or strata in the vicinity of the borehole, especially when, as is typical, the casing is cemented 40 to the borehole 41.

[0027] Contact forces for a cylindrical member such as a production tube or mandrel can be estimated using well-known torque and drag models. In this regard, FIG. 2 shows models for deriving these parameters, including the "soft string" model (top of FIG. 2) and the cantilever beam model (bottom of FIG. 2). The soft string model involves an analysis of the effects of torque and normal force on a cylindrical member under tension. The cantilever beam model involves an analysis of the effects of bending of the cylindrical member. An optimal approach for estimating the true effect of torque and drag can involve combinations of these two models, as one skilled in the art will recognize, and the use of such models may facilitate the designing or use of the mandrel disclosed herein.

[0028] It has been determined that otherwise inadvertent or unwanted contact between the production tube 1 and the casing 2 can provide a suitable mechanical coupling to allow sensors on the tube to receive and sense seismic signals. FIG. 3 shows such an implementation. In FIG. 3, mandrels 4 which house seismic sensor apparatuses 7 (not shown in FIG. 3) are permanently connected to production tubing 1 and become part of the production string, which is placed within the deviated bore hole. FIG. 3 shows the mandrels 4 in contact with the well casing 2, which as noted facilitates seismic sensing by the sensor apparatus 7. The mandrels 4 are designed, as will be explained in further detail later, so that they may be permanently deployed with the production tube 1, and allow seismic images to be procured over a period of time and without interrupting the production of oil/gas from the well. As also will be seen, the mandrels 4 are designed of rigorous construction, thus minimizing the possibility of breaking free from the production tube, and necessitating premature retrieval of the production tube 1. Moreover, the mandrels are designed to passively and naturally come into contact with the casing, and need not be intentionally or actively adjusted or oriented to establish such contact as in the prior art. The mandrel design also provides a simpler housing construction for the sensors over more traditional downhole seismic sensing techniques. While two mandrels 4 are shown in FIG. 3, one or more than two mandrels could also be deployed and brought into contact with the casing as will be described herein. In embodiments using fiber-optic-based sensors, there will preferably be several of the disclosed mandrels which are multiplexed along one or more fibers to form a seismic array. In an arrayed embodiment, the mandrels 4 are generally spaced at set distances within the well to allow several pick-up points for seismic data along the length of the well, thus increasing the extent of the earth formation that can be assessed.

[0029] FIG. 4 illustrates an embodiment of the mandrel 4. As shown, the mandrel 4 may comprise or be coupled to pipe ends 20 designed to couple with the otherwise standard sections of production tubing 1 at threaded members 6, although other known methods used to connect pieces of production piping can be used, such as by clamping. A premium thread with suitably high tensile strength, such as a VAM Ace certified threaded connection having a 233,000-pound minimum tensile capability (based on a VAM Ace Connection), well-known in the art, is suitable. These pipe ends 20 may in turn be similarly connected to the mandrel 4 (see for example FIG. 10). Alternatively, the mandrel 4 can slip over an otherwise standard section of production tubing 1, and may be bolted, clamped, welded, or otherwise fused to the tube 1 through any of several known standard means. Additionally, the mandrel 4 and associated pipe ends 20 may be milled or forged as an integrated unit.

[0030] The inner diameter 5 of the tube contained within the mandrel 4 (or the tube or pipe ends to which it is attached or constitutes a part of) is of a size necessary to allow fluids to flow to and from the production tubing 1 to which it is coupled and without impediment through the tube. In a preferred embodiment, the inner diameter 5 is substantially the same as the inner diameter of the otherwise standard sections of production tubing to which it is connected, which can vary from well to well as one skilled in the art will understand.

[0031] By contrast, the outer diameter 21 of the mandrel 4 is preferably larger than the outer diameter of the production tubing 1, but smaller than the inside diameter of the casing 2 into which it will be deployed. Preferably, the outside diameter 21 should be just smaller than that inside diameter of the casing 2 to ensure a high probability that the mandrel 4 will be brought into contact with the casing 2 at a point of deviation, non-linearity, or non-verticality within the well. In this regard, it is well known that casings within a well are subject to variation or drift, and accordingly that a particular well can be specified as having a particular drift diameter indicative of the smallest extent of the true inside diameter of the casing. It is preferred that the outside diameter of the disclosed mandrel be 1/8-inch smaller than the inner diameter of the casing, although other spacings can be suitable depending on the nature of the well environment in question and the degree of deviation, non-linearity, or non-verticality of the well. Of course, one skilled in the art will recognize that wells can have a variety of diameters, and accordingly that the disclosed mandrel 4 will take on a variety of different outside diameters in recognition thereof.

[0032] It is also preferable that the outside diameter 21 be larger than the outside diameter of any other structures on or connected to the production pipe 1, such as collars, to ensure that the mandrel 4 will be brought into contact with the casing 2. As it is desired for the mandrel 4 to come into contact with the casing 2 at points of deviation, non-linearity, or non-verticality, one skilled in the art will understand that the outside diameter 21 of the mandrel will be engineered to function acceptably with a casing 2 inner diameter of a given value.

[0033] The length L of the mandrel and the degree of curvature of the well casing at points of deviation, non-linearity, or non-verticality must also be considered when engineering the outside diameter 21 of the mandrel to ensure that the mandrel will touch, but not become stuck to or damage, the casing 2. A length of approximately 60 inches is presently preferred for the mandrel 4, although other lengths might be suitable for a given application. However, and as one skilled in the art will recognize, it may be desirable in a given application to make the mandrel 4 as short as possible to minimize any inherent resonances which might interference with the seismic measurements to be made. It is preferred that the mandrel be tapered 25 at its ends to ensure that the mandrel can slip through the casing 2 with relative ease without becoming stuck.

[0034] As shown in FIG. 4, the mandrel 4 houses a seismic sensor apparatus 7. The mandrel 4 contains a groove 8 for securely holding the sensor apparatus 7 in place. The groove 8 may be milled from the starting material from the mandrel 4, may be forged, or formed by many well-known metal-working means. As shown in FIG. 5, the sensor apparatus 7 preferably has a one or more cylindrical housings, and accordingly the groove 8 preferably has a cylindrical contour. The groove 8 runs preferably along substantially the entire length of the mandrel 4 and allows the sensor to be adjusted within the channel with about a 5-inch play, which can be beneficial in multi-sensor arrays to adjust the relative spacing between the sensor apparatuses from mandrel to mandrel.

[0035] Many different types of sensor apparatuses may be used in conjunction with the disclosed mandrel 4. In a preferred embodiment, the sensor apparatus 7 constitutes a sensor mechanism, such as disclosed in U.S. Patent Application having Express Mail No. EL830942248US and Attorney Docket No. 13137.0167.NPUS00, which is filed concurrently herewith, is entitled "Multiple Component Sensor Mechanism," and is incorporated herein by reference in its entirety. The sensor mechanism disclosed in this incorporated application includes a cylindrical housing for one or more sensors. When a fiber optic based sensor is used, the incorporated sensor mechanism can include one or more cylindrical housings for splice components, fiber organizers, and other devices associated with optical fiber. Use of the integrated sensor mechanism disclosed in this incorporated application is preferred due to the benefits provided by its assembly and its small, cylindrical profile, and due to the fact that the sensor mechanism does not need to be actively deployed to be brought in contact with the casing, as the mandrel 4 passively serves this function.

[0036] Many different types of sensors can be housed in the sensor apparatus 7 of the present invention. Preferably, the sensor constitutes a fiber optic based sensor containing at least one fiber Bragg grating. For example, the sensor apparatus 7 can have one or more accelerometers, such as disclosed in U.S. patent applications Ser. No. 09/410,634, filed Oct. 1, 1999 and entitled "Highly Sensitive Accelerometer" and Ser. No. 10/068,266, filed Feb. 6, 2002 and entitled "Highly Sensitive Cross Axis Accelerometer," which are incorporated herein by reference in their entirety. The accelerometers (not shown) can be positioned in any of the three axes (x, y, and z) and can transmit respective sensing light signals indicative of static and dynamic forces at their location on the optical fiber. Alternatively, the sensor apparatus 7 can constitute other sensors or sensor systems known in the art for use in a well.

[0037] It should be noted that well-known methods and techniques exist in the art for processing signals from sensors placed in a deviated, non-linear, or non-vertical well. For example, the sensor apparatus 7 can contain three accelerometers arranged in three orthogonal axes (x, y, and z) or can contain four accelerometers arranged along tetrahedral axes. When the sensor apparatus 7 is positioned in a deviated, non-linear, or non-vertical well, and assuming the use of a three-orthogonal-acceleromet- er arrangement, the three axes (x, y, and z) of the sensors will not be oriented to true vertical, and furthermore will have an unknown rotation. When interpreting the signals, known methods and techniques can account for the non-vertical orientation or tilt of the sensors in the well. For example, when the well is drilled, the deviation, non-linearity, or non-verticality can be determined through Measurement While Drilling (MWD) or well-logging techniques using, for examples, magnetometers or gyro tools. As is also known, geophysical methods, such as polarization analysis of direct arrivals of seismic waves emitted from a known source location, can be used to derive the rotated position of the sensors. By knowing tilt and rotation, the signals coming form the sensors can be processed or adjusted so that they reflect the true status of the earth formation.

[0038] The sensor apparatus 7 communicates with a cable 11, which is preferably a fiber optic cable for those instances in which a fiber optic based sensor apparatus 7 is used, but could also constitute a wire if an electrically based sensor apparatus 7 is used. As shown in FIG. 4, the fiber optic cable 11 emerges from both ends of the sensor apparatus 7. Such a dual-ended sensor apparatus 7 allow several sensors apparatuses to be multiplexed in series, or allows the sensor apparatus 7 to be multiplexed with other downhole fiber optic measuring devices, such as pressure sensors, temperature sensors, flow rate sensors or meters, speed of sound or phase fraction sensors or meters, or other like devices. Examples of such auxiliary sensing devices are disclosed in the following U.S. Patent Applications, which are hereby incorporated by reference in their entireties: Ser. No. 10/115,727, filed Apr. 3, 2002, entitled "Flow Rate Measurement Using Short Scale Length Pressures"; Ser. No. 09/344,094, filed Jun. 25, 1999, entitled "Fluid Parameter Measurement In Pipes Using Acoustic Pressures"; Ser. No. 09/519,785, filed Mar. 7, 2000, entitled "Distributed Sound Speed Measurements For Multiphase Flow Measurement"; Ser. No. 10/010,183, filed Nov. 7, 2001, entitled "Fluid Density Measurement In Pipes Using Acoustic Pressures"; and Ser. No. 09/740,760, filed Nov. 29, 2000, entitled "Apparatus For Sensing Fluid In a Pipe."

[0039] If only one sensor apparatus 7 is used, or for the last sensor apparatus 7 in a string, the fiber optic cable 11 need not proceed through both ends but may be single ended. Ultimately, cable 11 proceeds to the surface of the well along the edge of the production pipe 1 to a source/sensing/data collection apparatus as is well known, and which is capable of interrogating the sensor apparatus 7 and interpreting data retrieved therefrom.

[0040] The sensor apparatus 7 may be held firmly within the mandrel 4 by several means. In a first embodiment shown in FIGS. 4 and 5, the sensor apparatus 7 is held within the mandrel 4 using hinge clamps 9 hinged to the mandrel 4 using hinge rods 13. The hinge clamps 9 may be rotated over the sensor apparatus once it is in place and thereafter may be bolted to the mandrel 4 at bolt holes 22 by bolts 10. In a second embodiment, shown in FIG. 8, clamps 9 are not hinged, but instead are bolted at both ends to the mandrel using bolts 10 as shown. In a third embodiment, shown in FIG. 7, clamps 9 may be welded or brazed to the mandrel 4 at weld points 23. As it is generally important to protect the sensor apparatus 7 from the harsh downhole environment and to protect it from mechanical damage, it is generally preferred that a secure junction be made between the clamps 9 and the mandrel 4 such as those disclosed herein, although other like mechanisms may be used. As one skilled in the art will recognize, and depending on the design of the clamp 9, a single clamp can be used with a given mandrel 4, or several clamps can be used as shown. If a single clamp is used, that clamp can be made to span the entire length of the sensor apparatus 7, which might provide optimal sensor protection.

[0041] Other structures to secure the sensor apparatus 7 can be used. For example, and as shown in FIG. 10, the sensor can fit within a tunnel 17 formed in the side of the mandrel 4. The tunnel 17 is preferably milled or drilled into the mandrel 4, and preferably has a diameter just slightly larger than the outside diameter of the sensor apparatus 7 such that the sensor apparatus 7 slips into but is firmly held by the tunnel 17. In such a tunneled embodiment, it is preferably to place seals 18 at the ends the tunnel 17 to ensure that the sensor apparatus 7 stays in place when deployed. These seals 18 could be made in any number of ways as one skilled in the art will recognize. For example, they could comprise elastomer seals that press fit into the ends of the tunnel 17 or screwable seals which mates with threads form on the inside of the tunnel.

[0042] In a preferred embodiment, and referring to the cross-sectional view of FIG. 6A, channels 12 are formed on the side of the mandrel 4 to allow for the bypass of fluids or gases (and some solids of minimal dimension) that might be located in the annulus between the production pipe 1 and the casing 2, such as mud, oil/gas, water, or other caustic drilling agents. (These channels 12 can also be seen in the illustrative embodiments of FIGS. 4 and 5, but are not shown in the other figures for clarity). These channels 12 are preferably milled from the starting material for the mandrel, but may also be forged, stamped, or formed by any other well-known metal-working processes. Although four such channels 12 are shown in FIG. 6, more of fewer channels could also be formed, and such channels could be made of differing sizes and shapes. Additionally, the channels 12 need not be parallel, but could for example be comprised of helical twist grooves, serpentine patterns, etc.

[0043] The tube 5 within the mandrel is preferably concentric with the outer diameter of the mandrel 4, as shown in FIG. 6A, which facilitates deployment and retrieval of the mandrel and maximizes the chance that the mandrel 4 will not inadvertently become stuck in the casing. However, the mandrel 4 can be positioned such that it is not concentric with the tube 5, but instead sits off center, as shown in FIG. 6B. This orientation allows extra room for the groove 8 or tunnel 17 which houses the sensor apparatus 7, and, despite the risk of sticking, may help facilitate mechanical coupling between the mandrel 4 and the casing 2, because the inner mandrel tube 5 will be inclined, by virtue of its connection to the production pipe, to generally center itself within the casing 2. Such non-concentric embodiments may cause a minor degree of flexure in the production pipe, which may not be desirable in some applications and environments.

[0044] Other variations in the topology of the mandrel 4 are possible to allow for the flow of fluid around the mandrel in the annulus. For example, and referring to FIG. 9, an elliptical shape is provided for the outside surface of the mandrel 4. As with the other embodiments disclosed herein, the maximum diameter of the ellipse is preferably as large as possible, e.g., 1/8 inch short of the inner diameter of the casing, but still small enough to pass through the casing 2. The minimum diameter defines a channel 12 allowing for the passage of fluids or other materials in the annulus.

[0045] The mandrel 4 is preferably as stiff as possible to ensure good acoustic coupling between the seismic events to be detected and the sensor apparatus 7, but can be comprised of any number of materials typically used for downhole tools. High strength, anti-corrosive materials, such as stainless steel, are suitable. Construction of the mandrel using such materials, and using a 5.5-inch diameter mandrel, will result in a mandrel component weighing about 150-200 pounds. Of course, the design of mandrel 4 is preferably modified depending on the environment (well) in which it is to be placed, which can vary from well to well in terms of their pressures, temperatures, and exposure to caustic chemicals. The material of the mandrel 4 may need to be modified if sufficient amounts of hydrogen sulfide, or "sour gas," are present, and such sour gas resistant metallurgies are well known to those of skill in the art. Additionally, stabilizing or stiffening structures could also be included within the mandrel body.

[0046] As discussed, it is preferable when making seismic measurements for the disclosed mandrel to touch, i.e., mechanically couple to, the casing and hence the earth formation under analysis. It is preferable that the mandrel not rock, sway, or torque within the casing, which it might be prone to do given the turbulent nature of the downhole environment. In this regard, other shapes for the mandrel might be employed to improve coupling and to maximize the probability of holding the mandrel steady during the receipt of seismic measurements. (The above-disclosed "round" mandrels, while believed suitable for some or most applications, might function less well in such turbulent environments.)

[0047] Accordingly, for those applications requiring firmer mechanical coupling, the design of the mandrel could be changed. One example of such a change is shown in FIG. 11, which shows a mandrel 4 that is triangular in cross section. As shown in that Figure, when the mandrel 4 touches the casing 2, it will touch at the outer points 31 of the triangular cross section. Because, as in the other embodiments, the outer diameter of the triangle (were it circumscribed in a circle) is just smaller than the inner diameter of the casing, e.g., by 1/8 inch, chances are improved that the mandrel 4 will touch the casing 2 at two points 31 at a given cross section, i.e., at two points of the triangle, as shown in FIG. 11. (By contrast, a circular mandrel will only touch the casing at one point at a given cross section). Touching the casing at two points 31 will tend to prevent the mandrel 4 from torquing or rolling with respect to the casing 2, and hence may help in a given application to hold the mandrel steadier with respect to the casing when compared with round mandrel embodiments. Of course, other cross sectional shapes may achieve these same beneficial results, such as squares, hexagons, etc., and these shapes may also be beneficial in that they might add mechanical stability or stiffness to the mandrel. Furthermore, such shapes will naturally form channels 12 with respect to the side of the casing to allow for the flow of materials past the mandrel in the annulus. Such alternative polygonal cross sections need not be formed of straight lines, but could be bowed, as represented by dotted line 28 in FIG. 11 (which might require the positions of the inner pipe and sensor apparatus 7 to be adjusted within the mandrel).

[0048] The foregoing benefits of these alternative polygonal embodiments can also effectively be realized using an otherwise round mandrel. For example, in FIG. 12, there is disclosed a mandrel 4 that is otherwise similar to the rounded embodiments disclosed in FIGS. 4-10, but includes protrusions 30. The protrusions 30 project radially from the mandrel 4 and are designed to contact the casing 2 in much the same way that the polygonal embodiments of FIG. 11 would, i.e., preferably at two points of contact. The protrusions 30 define, in FIG. 12, a hexagon, but other polygonal shapes are possible. The protrusions preferably run along the entire length of the mandrel 4, but may also appear at certain points along it length, or only at the top and bottom of the mandrel where they are most likely to touch. Although not shown, the protrusions 30 may be tapered to reduce the possibility of catching on the casing 2 as the mandrel is deployed downhole. The protrusions 30 can be milled from the body material for the mandrel, or may be attached by any well-known metal-working techniques, such as brazing, bolting, clamping, etc. As with the other embodiments, the outer diameter of the protrusions (were they circumscribed in a circle) are preferably just smaller than the inner diameter of the casing to improve the chances of mechanical coupling to the casing. The protrusions may constitute many different shapes suitable for coupling with the casing, such as rounded bumps, and may comprise different heights or thicknesses.

[0049] The foregoing thus discloses a seismic sensing mandrel constructed of minimal parts, and which is of a suitably solid construction to house and protect the preferred fiber optic sensors disclosed herein. However, the mandrel 4 is also easily adapted to house more traditional seismic sensors, such as those that are electrically and/or mechanically based. The mandrel is also easily adaptable to house other such structures or their cabling. For example, additional channels or tunnels could be formed in the mandrel 4 to allow for the passage of additional electric or fiber optic cables. As disclosed, the mandrel meets or exceeds strength requirements for production tubing.

[0050] FIG. 13 discloses a design for bringing the mandrel 4 into contact with the casing 2, again using natural forces. In FIG. 13, a displacement device 35 is shown connected to the production pipe near the mandrel. The displacement device 35 is designed to displace the production pipe from its natural center within the casing, and accordingly has a radius D.sub.2 which is preferably just larger than the average distance D.sub.1 between the outside diameter of the production pipe 1 and the inside diameter of the casing 2. The displacement device will generally touch the casing 2 throughout its entire length as the production pipe 1 and the mandrel 4 are deployed. To reduce the chance of catching during deployment, the displacement device 35 may be tapered as shown. By displacing the production pipe 1, the mandrel 3 is likewise displaced within the casing 2, improving the chance of mechanically coupling the mandrel to the casing. Because the production pipe 1 is somewhat flexible, both the mandrel 3 and the displacement device 35 should be able to slip through the casing 2 without issue, with areas of friction or undesirable narrowness in the casing 2 being relieved by slight bending of the production pipe 1. To ensure that the pipe 1 is not overstressed or bent to the point of fracture, it may be desirable to place the displacement device 35 at a suitable distance from the mandrel 3. To further reduce such unwanted stresses on the production equipment, it may be necessary in some applications to design the displacement device 35 and the mandrel in highly tapered configurations to reduce the chances of catching on the casing. It should be noted that this embodiment may generally cause the mandrel 3 to contact the casing even in locations where the casing is perfectly vertical, and hence improves the ability of the disclosed mandrel to take sensor measurement even in non-deviated wells or wells of only slight deviation, non-linearity, or non-verticality. The displacement device may comprise many known structures, but in a preferred embodiment comprises a solid block or fin of steel bolted to the production pipe. Other structures 35 capable of displacing the production tube 1 and/or the mandrel 4 and methods for affixing such structures to the pipe 1 are well within the purview of those skilled in the art. Although shown above the mandrel 4 on the production pipe, the displacement device 35 will serve the same function if mounted below the mandrel 4 on the pipe 1. If multiple mandrels on used on a given production tube, multiple displacement devices 35 may be used as well.

[0051] While particularly useful for the deployment of sensors usable for vertical seismic analysis, the disclosed mandrel will have utility for the deployment of other types of sensors as well, such as pressure and temperature sensors. Additionally, while the disclosed mandrel is particularly useful in deviated, non-linear, or non-vertical wells, it can have utility for the deployment of other sensors that need mechanical rigidity but that would not necessarily benefit from contact or mechanical coupling with the well casing.

[0052] The term "outside diameter" as it applies to the mandrel should be understood as referring to the outside diameter of a circle that circumscribes the mandrel and its accompanying structures if any. Accordingly, all of the disclosed embodiments disclosed herein, be they circular or not, and including those of polygonal cross section or having protrusions extending from the body of the mandrel, should be understood as having an "outside diameter." Contacting the mandrel to the well by "natural force" denotes contact between the mandrel and the casing without active actuation of any devices capable of facilitating such contact and without active intervention on the part of the production engineer.

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