WO2001046555A1

WO2001046555A1 - System and method for telemetry in a wellbore

Info

Publication number: WO2001046555A1
Application number: PCT/GB2000/004751
Authority: WO
Inventors: Richard John Meehan; Charles Roderick Jenkins; Benjamin Peter Jeffryes; John Mervyn Cook
Original assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Holdings Ltd
Current assignee: Schlumberger Canada Ltd; Services Petroliers Schlumberger SA; Schlumberger Technology BV; Schlumberger Holdings Ltd
Priority date: 1999-12-22
Filing date: 2000-12-12
Publication date: 2001-06-28
Anticipated expiration: 2002-06-22
Also published as: GB9930343D0; US20040035608A1; GB2357527A; AU2195301A; DE10085315T1; NO20023000D0; GB2357527B; CA2395082A1; NO20023000L

Abstract

A method and apparatus for creating a telemetry signal in a drillstring is disclosed. Opposite torsional forces are imparted on the drillstring at two or more different locations. A steel shaft inside the drillstring is coupled to the drillstring via electromagnetic actuators at end and rigidly attached to the drillstring at the other end. A similar method and apparatus for generating axial telemetry signal in the drillstring is also disclosed.

Description

SYSTEM AND METHOD FOR TELEMETRY IN A WELLBORE

FIELD OF THE INVENTION:

The present invention relates to the field of telemetry in hydrocarbon wellbores. In particular, the invention relates to a system and method for creating torsional telemetry signals in a drillstring during the development of a hydrocarbon wellbore.

BACKGROUND OF THE INVENTION:

Communication between downhole sensors and the surface has long been desirable. This communication is, for example, an integral part of methods known as Measurement-While-Drilling (MWD) and Logging-While- Drilling ( WD) . Various methods that have been tried for this communication include electromagnetic radiation through the ground formation, electrical transmission through an insulated conductor, pressure pulse propagation through the drilling mud, and acous- tic wave propagation through the metal drill string.

Each of these methods has disadvantages associated with signal attenuation, ambient noise, high temperatures and compatibility with standard drilling procedures. The most commercially successful of these methods has been the transmission of information by pressure pulse in the drilling mud. However, attenuation mechanisms in the mud limit the effective transmission rate to less than 10 bits per second, even though higher rates have been achieved in laboratory tests. Additionally, conventional mud pulse telemetry fails during drilling with highly compressible fluids, such as gassified muds and foams. These fluids are finding an increasing market in underbalanced drilling. Reliably maintaining under-balance requires real-time monitoring of downhole annular pressure. Therefore, in underbalanced drilling, high data rate telemetry is important .

An alternative is to use axial or torsional stress waves in the drillstring. The idea of using torsional acoustic waves in a drillstring as a telemetry signal is not new. There have been several US patents issued for devices which can excite torsional vibrations .

US 4,001,773 describes a method in which a telemetry "signal" is generated by drilling noise, or noise caused by other rig operations. This signal travels along the drillstring and is detected at surface. The signal is modulated by means of an inertial mass in the bottom hole assembly ("BHA"). This mass is coupled to the drillstring by means of an electromagnetic clutch. Engaging or disengaging the clutch changes the transmission characteristics of the drillstring, hence modulating the signal. The disadvantages of this type of arrangement include a lack of control over signal source, which depends upon the particular drilling operation, and its mechanical complexity in terms of substantial moving parts.

US 5,159,226 and US 5,166,908 describe a system in which a Piezo-electric device mounted on a stub shaft which fits within the drillstring. One end of the shaft is provided with a threaded connection and can be fixed to the drillstring. When the Piezo crystals are energised, they cause the stub shaft to twist and the torque generated is transmitted to the drillstring. A reaction mass can be connected to the free end of the stub shaft to increase the amplitude of the signal, although this will decrease the bandwidth of the signal. Other disadvantages of this arrangement include the mechanical complexity and the relative fragility of the Piezo crystal material .

US 4,462,469 describes a system that uses a hydraulic downhole motor, which derives energy from the mud, but without allowing the mud to come into contact with the moving parts of the motor. It works by using flexible bellows or moveable walls to pressurise the motor fluid. Changing the settings of choke valves in the motor by means of control solenoids causes torsional impulses to be applied to the drillstring. Disadvantages of this type of arrangement include the large number of moving parts, the mechanical and hydraulic complexity, and the relatively low frequency response due to hydraulic limitations.

US 4,992,997 describes a torsional wave generator which comprises two or more eccentric rotors driven by electric motors. By controlling the rotation speeds and relative phase of the motors, torsional vibrations may be set up in the drillstring.

Disadvantages of such an arrangement include the high number of moving parts and the relative mechanical complexity.

US 4,283,779 describes a device that uses an inertial mass in the BHA. A torque is produced between this mass and the drillstring by directing mud from the drillstring into chambers within the inertial mass. This causes relative rotation between the drillstring and the inertial mass, and the resulting torsional impulse propagates up the drillstring. Disadvantages of this type of arrangement include the substantial moving parts, as well as the requirement for high pressure solenoid valves .

SUMMARY OF THE INVENTION:

Thus, it is an object of the present invention to provide a telemetry system that is capable of higher data rate than conventional mud pulse telemetry systems. It is a further object of the invention to provide a telemetry system that does not depend upon the drilling fluid (i.e. it will work when drilling with gas cut mud, foam or air) .

It is a further object of the invention to provide a torsional signal source for wellbore telemetry that is relatively simple mechanically, has relatively few moving parts, and is not prone to mechanical failure during downhole operation.

According to the invention a method and apparatus for creating a telemetry signal in a drillstring is provided. The invention involves imparting a force on the drillstring at a first location, and imparting another force to the drillstring at a second location. The two forces act in opposite directions. The forces can be axial in direction, however according to the preferred embodiment the forces create a torsional telemetry signal. Forces can be imparted on the drillstring at more than two locations. However, when forces are imparted in only two locations, the magnitude of two forces is substantially equal.

The invention preferably involves generating an acoustic wave that propagates though a member that is coupled to the drillstring at the two locations. The member is preferably a steel hollow shaft having a circular cross section being positioned inside the drillstring. The shaft is preferably coupled to the drillstring via electromagnetic actuators at one location, and rigidly attached to the drillstring at the other location. The invention also preferably includes receiving the acoustic signals at the surface, converting the acoustic signals into electromagnetic signals; and recording the electromagnetic signals. The invention also preferably includes a baffle located on the drillstring between the telemetry source and the drill bit to suppress torsional waves in a predetermined frequency range, which are created in the drillstring by the drilling process.

BRIEF DESCRIPTION OF THE DRAWINGS:

Figure 1 shows a borehole during drilling and a telemetry system, according to a preferred embodiment of the invention; Figure 2 schematically shows a torsional telemetry source, according to a preferred embodiment of the invention;

Figure 3 shows an example of the sort of torsional waves as measured at a range of positions along the drill string, according to an embodiment of the invention;

Figure 4 shows a perspective view of a section of drill collar and an inner shaft for a torsional source, according to an embodiment of the invention;

Figure 5 shows an exploded view of one of the actuator sections depicted in Figure 4, according to a preferred embodiment of the invention; Figure 6 shows a plan view of electromagnetic actuators used in a torsional telemetry source according to a preferred embodiment of the invention;

Figure 7 shows an example of the transmission response of a drillstring for torsional waves; Figure 8 shows a torsional source having more than one set of magnet/coil arrangement along the length of the shaft, according to an embodiment of the invention; and

Figure 9 shows a subasse bly for creating axial waves in the drillstring, according to an embodiment of the invention.

DETAILED DESCRIPTION OF THE INVENTION:

Figure 1 shows a borehole during drilling and a telemetry system, according to a preferred embodiment of the invention. Although derrick 44 is shown placed on a land surface 42, the invention is also applicable to offshore and transition zone drilling operations. Borehole 46, shown in dashed lines, is being formed using bit 54 and drill string 48. The lower portion of drill string 48 comprises a bottom hole assembly

("BHA") 56. The BHA 56 in turn, comprises a number of devices, including MWD tools 60, baffle 62 and telemetry subassembly 64.

The downhole end of the drill string 48 comprises a drill collar, not shown, which is heavy- section of drill string assembled from sections of collar pipes with increasing diameter having an typical length on the order of 300 meters (1000 feet) . A drill bit is attached to the downhole end of the drill collar, with the weight of the collar causing the bit to bite into the earth as the drill string is rotated from the surface. Sometimes, downhole mud motors or turbines are used to turn the bit. Above the drill collars is drill pipe 58. Drill pipe 58 is made up of great number of drill pipe joints (not shown individually) .

At the surface 42, are located the circulating system, not shown, for circulating the drilling mud, rotating system, not shown, to rotate the drill string and drill bit, and a hoisting system, not shown, for suspending the drill string with the proper force .

According to the invention, data from the MWD tools 60 transmit MWD data to the telemetry subassembly 64 via a cable, not shown. Telemetry subassembly 64 then converts the data from electrical form to torsional signals, or torsional waves, in drill string 48. The torsional waves propagate up the drill string to the surface, where they are detected by torsional signal receiver 66. Receiver 66 converts the torsional waves back into electronic form and then transmits the data to a logging unit 68 for recording and further processing. Logging unit 68 comprises a computer, data storage, display and control logic.

In general, there are many possible embodiments for receiver 66 and control system 68. A subassembly fitted below the top drive or kelly can be instrumented with strain gauges or magnetostrictive sensors to sense the passage of the torsional waves. The signals generated may then be transmitted to logging unit 68 by means of radio transmission, inductive transmission, slip rings, etc. Alternatively, the subassembly could be fitted with accelerometers mounted so as to be sensitive to variations in rotational acceleration. Alternatively, the subassembly could be fitted with both accelerometers and strain gauges or magnetostrictive sensors .

According to another embodiment, the subassembly could be fitted beneath the top drive or kelly equipped with a reflecting band on its outer circumference. A laser unit mounted at some remote location can direct a laser beam at the reflecting band, and record the signal scattered from it. Subsequent processing of this signal can be carried out to detect the variations in rotation speed caused by the torsional oscillations. However, the preferred method for use in receiver 66 is a strain gauges (or strain gauges and accelerometers) mounted on a subassembly with batteries and a radio transmitter to communicate with logging unit 68.

According to a preferred embodiment, baffle 62 is provided to suppress certain frequencies of torsional waves coming from bit 54. The frequencies suppressed include the bandwidth that is being used for the torsional telemetry system. For a further description of such a baffle system, refer to published UK Patent Application No. GB 2 327 957 A, incorporated herein by reference.

According to an alternative embodiment of the invention, the telemetry subassembly could be placed further up the drill string, as is shown by telemetry subassembly 70 in Figure 1. According to this embodiment, MWD data from MWD tools 60 is transmitted to the telemetry subassembly 70 via a transmission cable, not shown, running inside the drill string. The Telemetry subassembly 70 would then operate as described above with respect to subassembly 64. However, according to this embodiment, the frequencies of torsional waves used for the telemetry could be in general of higher frequency, since the overall attenuation would be lower due to the shorter path length between the torsional source and the receiver.

Figure 2 schematically shows a torsional telemetry source, according to a preferred embodiment of the invention. Torsional source 100 comprises a shaft 114, which fits within a piece of drill string 110. If the torsional source 100 is mounted in the BHA as shown in location 64 in Figure 1, then the 110 will be a section of the drill collar. If the torsional source is mounted further towards the surface, as shown in location 70, then 110 would be a special adapted section of the drill string.

Referring again to Figure 2, shaft 114 is made of an elastic material, preferably steel which fits inside a piece of drill string (either drill collar or drill pipe) . The lower end of shaft 114 is rigidly fixed to the drill string at fixing point 112. Mounted at the upper end of shaft 114 there is an arrangement of permanent magnets 122. Coils of conducting wire 120 are mounted on the inside of the drill string 110 in close proximity to magnets 122. The magnets and coils are arranged in such a way that when the coils are supplied with current, a twisting force is exerted on the shaft, and an equal and opposite twisting force is exerted on the drill collar. This arrangement is similar to that of an electric motor, for example a stepper motor. The shaft is similar to the rotor of the motor, while the coils are similar to the stator. Together, the magnets and coils form electromagnetic actuators 124 and 126. When a varying current is supplied to the coils, the resultant magnetic fields cause the shaft to try to turn.

If, for example, coils 120 are energised in such a way as to produce a torsional force on the rotor (the shaft), an equal and opposite reaction torque will be exerted on the stator (i.e. the body of the drill collar) . This will generate counterclockwise torsional wave in the drill collar. Arrow 129 illustrates the direction of such a force imparted on the drill string. As a result of the force illustrated by arrow 129, a torsional wave will propagate along the drill string 110, both upwards towards the surface, and downwards towards the bit. At the same time the clockwise torque exerted on the rotor produces a torsional wave travelling along the shaft 114. When this wave reaches the fixing point 112 of shaft 114 it will impart a clockwise torsional force on the drill collar. This clockwise force is illustrated by arrow 128. The clockwise force will generate a torsional wave in the drill string which will travel both upwards to the surface and downwards towards the bit. The time delay between the initial counterclockwise wave travelling in the drill string, and the second clockwise wave, will depend upon the length of the shaft between the magnet/coil arrangement and the fixing point, and upon the material properties of both the shaft and the drill collar.

When the torsional wave travelling along shaft 114 reaches the fixing point 112, some of the energy will be reflected back upwards along the shaft. It will travel back to the upper end of shaft 114 where it will be reflected once again towards the fixing point 112. When it reaches the fixing point some more of the energy will be transmitted to the drill string and the remaining energy reflected back along the shaft. In this way the energy of the initial wave in the shaft gradually "leaks out" to the drill collar, generating a series of pulses which decay in amplitude. Torsional source 100 thus relies for its operation on the elasticity of the drill string (either the drill collar or the drill pipe) and the shaft. Advantageously, there are no sliding contacts. According to an alternative embodiment, the magnet could instead be mounted on the drill string 110, and the coil could be mounted on the shaft 114. Alternatively, the magnets are be replaced by coils, i.e. coils are located on the shaft and the drill string. According to this embodiment, by supplying current to both sets of coils in an appropriate manner, the same type of torsional forces would be produced as described above.

In general, the shaft may be fixed to the drill string at any single point along its length. The shaft also need not be axially symmetric and its cross sectional area may change along its length, and the material properties of the shaft may change along its length. Figure 3 shows an example of the sort of torsional waves as measured at a range of positions along the drill string, according to an embodiment of the invention. The example shown in Figure 3 is for an initial torsional impulse generated at the magnet/coil end of the shaft of the arrangement shown in Figure 2. The example shown in Figure 3 assumes that both the drill collar (or in general the drill string) and the shaft are made from the same kind of steel. The waveforms show the torque measured at various points along the drill string after an initial torsional impulse (counterclockwise in the collar, clockwise in the shaft) has been generated by the magnet/coil arrangement. The relative amplitudes of the impulses depend upon the relative impedances of the shaft and the drill string. By varying the stiffness and impedance of the shaft, the relative timing and amplitudes of the multiple impulses can be controlled. In the example shown in Figure 3, the shaft length is 10 meters long.

Figure 4 shows a perspective view of a section of drill collar and an inner shaft for a torsional source, according to an embodiment of the invention. Drill collar 210 is slightly over 3 meters in length. Inside drill collar 210 is inner shaft 220. Inner shaft 220 is rigidly fixed to the drill collar 210 at the right end of the drill collar 212. The method of fixing is preferably threaded connection such as used in drill pipe, or welds. At the left end of drill collar 214 are a number of actuator sections 214. The outer portions of the actuator sections form an integral part of the overall drill collar. The preferred method of connecting the outer portions of the actuators to each other and to the rest of the drill collar is using a threaded connection. The inner shaft 220 comprises an enlongated section 226, that is 3 meters long in this embodiment, and inner portions of the actuator sections 228. In practice the length of the shaft should be chosen with respect to the preferred frequency band used for telemetry and the material properties of the shaft. Preferably, the shaft length should be chosen such that the frequency band chosen for telemetry does not coincide with any resonant frequency of the shaft. In a preferred embodiment the second pass band (see below, Figure 7 and associated text) is used for telemetry, a steel shaft length of 3 meters is appropriate. The inner portion of one actuator section is shown at 224. Each of the actuator sections comprises two or more sets of coil and magnet pairs. Although four actuator sections are shown in Figure 4, in general the number of actuators would depend upon the required force and frequency response of the actuator and driving circuitry. As discussed below, it has been found that several smaller actuators can provide greater bandwidth than one larger actuator.

When the actuators are operated, a force can be imparted on the drill collar on near the actuators, as shown by arrow 216. When the torsional wave in the shaft reaches the far end of the drill collar section, a force of the opposite direction is imparted in the drill collar at location 212, as illustrated by arrow 218.

Figure 5 shows an exploded view of one of the actuator sections depicted in Figure 4, according to a preferred embodiment of the invention. 240 is the drill collar section. 242 are the outer electromagnets, which are preferably coils of copper wire. The electromagnets 242 are rigidly mounted to drill collar section 240. Inner cylinder section 244 corresponds to the inner portion of the actuator section 224 shown in Figure 4. Inner cylinder section 244 is rigidly mounted to the inner shaft, and to the other inner cylinder sections. Inner permanent magnets 246 are mounted to the inner cylinder section 244.

In designing the actuators one should consider the desired levels of torque, the desired bandwidth of response, available power and space

(including space for a mud channel) . The preferred actuator is, in essence, a magnetic circuit containing an electromagnet and a powerful permanent magnet. Modulating the current in the electromagnet causes variable forces to be generated across air gaps in the circuit. Using standard magnetic circuit theory, the size of the forces can be calculated; they are, to good approximation, linear in the applied current. This means that the motor is easily controllable for modulating the torsional waves.

Permanent magnets are preferred since the downhole systems will need large air gaps (for example, 1 mm) , and critical alignments are undesirable in robust downhole systems. Standard theory shows that permanent magnets are preferred to achieve large forces in these circumstances. Moreover, the forces become relatively insensitive to the precise size of the air gap. In addition, this theory shows that there is an optimum size of magnet to use, once the size of the air gaps is stipulated. (Note that the phrase "air gap" applies even when the space between the circuit elements is filled with drilling fluid, as it has a relative magnetic permeability very close to that of air . ) Figure 6 shows a plan view of electromagnetic actuators used in a torsional telemetry source according to a preferred embodiment of the invention. A simple magnetic circuit is arranged to fit into the available space, which is within the drill collar 310 (or in general, the drill string) . The outer electromagnets 326 and 320 are rigidly fixed to the drill collar 310. Electromagnets 326 and 320 are wound with copper wire 350 and 354 respectively. Although a few windings are shown for illustrative purposes, in practice there will be a many windings over the section 352 of electromagnet body 326 in order to create the appropriate amount of magnetic flux. Similar windings are found on body 320.

Rotor section 312 comprises inner sections 318 and 324, which provide the return path for the magnetic flux, and house the permanent magnets 316 and 328. Inner sections 318 and 324 are rigidly mounted using support posts to the inner shaft (not shown) of the torsional source. Air gaps 330, 332, 334, and 336 are shown between inner sections 318 and 324 and electromagnets 326 and 320 respectively. The detailed magnetostatic design can be carried out by standard finite element methods for solving the Maxwell equations. At this level, the analysis accounts for losses due to the finite permeability of the elements of the magnetic circuit, and flux "short-circuiting" across gaps other than the air gaps . An important design concern is the need to maintain space for the mud channel, while keeping the electromagnet as separate as possible from the circuit elements carrying the returning flux. A central opening 314 is provided to allow for mud flow through the torsional source. Preferably, the torsional source is designed such that drilling mud (or other drilling fluid) can pass safely though the source. Seals are provided (not shown) to prevent contamination of the actuators, especially the air gaps from the drilling mud, which can negatively effect the actuator performance due to abrasion and excess wear. At another location, not shown in Figure 6, the drill collar 310 and the shaft are fixed, as described above. Due the elastic properties of the steel shaft and the drill collar, a small amount of rotary movement is thus possible between rotor section 312 and drill collar 310. The presence of the permanent magnets 316 and

328 cause an attactive force across the air gaps 330, 332, 334, and 336. In operation, an electrical current is passed though windings 350 and 354 generating a magnetic field though electromagnets 326 and 320. A significant portion of the magnetic flux passes across the air gaps and through inner sections 318 and 324, thus modulating the attractive force across the air gaps. If the current through the windings is in one direction, the attractive force is increased across the air gaps. This would result an increase in the counter-clockwise force applied to the drill collar 310, as shown by arrows 340, 342, 344 and 346. If the current is in the reverse direction, the counterclockwise force is decreased. The design shown in Figure 6 demonstrates the feasibility of placing circuits next to each other; more force is obtained if the permanent magnets are orientated oppositely in the two circuits . The effectiveness of the actuator in generating force is limited by the finite permeability of the steels used to manufacture the circuit elements. A fully optimised design should balance permeability against core losses (see below) for available materials. The power consumption of the actuator is almost entirely attributable to core losses, namely the irreversible process of driving the steel around its magnetisation curve. Preferably, the steel in inner sections 318 and 324, and electromagnets 326 and 320 consists of thin laminations, so that eddy current losses are very small. Note that it is important not to short-circuit the laminations with the support posts. In the configuration shown in Figure 6, resistive losses in the windings of the electromagnet are negligible. Preferably, several separate actuators such as that shown in Figure 6 are used to generate the desired levels of torque. This advantageously allows for increased bandwidth. In order to achieve the desired force from a single unit requires an electromagnet with a larger number of windings . Such a system would have a larger inductance, and hence a poorer bandwidth. Since the force generated by the motor is linear in the number of windings, while the inductance is quadratic in this quantity, using several smaller actuators is the preferred arrangement .

Figure 7 shows an example of the transmission response of a drillstring for torsional waves. The basis for the example is a drillstring that comprises several sections including a 780 meter long section of 5 inch 19.5 lb/ft drill pipe, followed by 112 m of 5 inch 50 lb/ft heavy wall drill pipe, 100 m of 6 inch drill collar, and finally a 100 m long section of 8 inch drill collar terminated by the drill bit. The structure of the drillstring gives rise to a transmission response as depicted in Figure 7. Though the analysis is made for torsional waves, a similar response spectrum can be derived for other wave forms (e.g. axial waves). According to the transmission response of the drill string signal transmission should be possible in any of the various pass bands. That is, the frequency ranges 0 to 120 Hz (first pass band) , 180 to 260 Hz (second pass band) and above 370 Hz (third pass band) , and so on. The pass band used for transmission of the torsional signal should be considered when designing the torsional source. In general choosing a higher frequency pass band allows an increase in the data rate, but leads to greater attenuation of the signal for a given length of drill string.

According to a preferred embodiment of the invention, the torsional source as described herein generates signals in the second passband, and the noise from the drill bit is suppressed using a baffle as described in published UK Patent Application No. GB 2 327 957 A. The general arrangment is shown in Figure 1.

Figure 8 shows a torsional source having more than one set of magnet/coil arrangement along the length of the shaft, according to an alternate embodiment of the invention. According to this embodiment, shaft 134 is rigidly mounted to drill collar 110 at fixing point 136. Towards the upper end of shaft 134 are two pairs of actuators 130 and 132. Towards the lower end of shaft 134 are actuators 140. Note that the cross section of shaft 134 varies between the portions above and below fixing point 136. Also shown are seal 160, and bearings 154 and 152. The seals are provided to prevent contamination of the actuators by drilling mud. The bearings are arranged to protect shaft 134 and the actuators from lateral shock. The bearing should thus allow torsional rotation but resist lateral movement. Additionally, the upper end of shaft 134 has a tapered section 142, so as to promote better mud flow though the telemetry subassembly.

The magnets may be fixed to the shaft, and the coils to the drill collar. Alternatively, the coils may be fixed to the shaft, and the magnets to the drill collar. A third option would be to have no magnets, but coils fixed to both the shaft and the drill collar. In operation, actuators 130 and 132 can impart a torsional force on the drill collar in one direction, and the actuators 140 can impart a torsional force on the drill collar in the opposite direction.

The force imparted at the fixing point 136 will depend upon the relative amplitudes and directions of the forces from the actuators, the timing of the forces, and the elastic properties of the shaft and the drill collar. In general, there may be any number of magnet/coil or coil/coil arrangements along the length of the shaft. The magnets and coils at one location do not have to be of the same size or design as those at another location. By providing more than two locations where torsional force can be imparted on the drill collar, and by providing different elasticities in the shaft the shape of the torsional wave may be manipulated in order to best transmit the desired signal. In general, the cross section of the shaft may vary along its length, and the shaft need not be in the form of a hollow cylinder. For example, the shaft could be in the shape of a torsional spring. However provision should be made for the flow of drilling fluid. Additionally, by using shaft materials having different properties, the nature of the resulting torsional wave can be affected.

Figure 9 shows a subassembly for creating axial waves in the drillstring, according to an embodiment of the invention. Axial source 410 comprises drill collar 412, inner shaft 420, and electromagnetic actuators 430 and 432. Shaft 420 is preferably a hollow cylinder and is rigidly mounted to the drill collar at fixing point 416. The electromagnetic actuators 430 and 432 are arranged so as to impart an upwards axial force as shown by arrows 440 and 442. The equal and opposite force generates an axial wave that propagates down shaft 420 and then imparts a downwards axial force on the drill collar at location 416 and 414. As in the torsional case, a portion of the energy is embodied in a reflected wave that travels back up the shaft. Actuators 430 and 432, have the magnets mounted on the shaft and the coils on the drill collar. However, as in the torsional case, an opposite mounting may be provided. Alternatively, there may be coils on both the shaft and the drill collar (no magnets) . The axial source subassembly 410 can be located either in the BHA, as shown at location 64 in Figure 1, or at a location closer to the surface, such as location 70. In the case of placing the axial source at location 70, a cable or the like is use to communicate with the tools in the BHA.

While preferred embodiments of the invention have been described, the descriptions are merely illustrative and are not intended to limit the present invention. For example, although much of the description herein is directed to torsional wave generation, the methods and structures described are also applicable to axial wave generation. Additionally, method of actuation other than electromagnetic can be used in many of the structures described to generate torsional or axial telemetry signals .

Claims

CLAIMSWhat is claimed is:

1. A method of creating a signal in a drillstring comprising the steps of: imparting a first force on the drillstring at a first location; and imparting a second force to the drillstring at a second location, the first force and the second force being in opposite directions.

2. The method of claim 1 wherein the first and second forces are torsional forces.

3. The method of claim 1 wherein the first and second forces are axial forces .

4. The method of claim 1 wherein the magnitude of the first and second forces are substantially equal.

5. The method of claim 1 further comprising the step imparting a third force on the drillstring at a third location, and the sum of forces imparted on the drill string is substantially equal to zero.

6. The method of claim 1 wherein the second force is imparted at a time delay after the first force is imparted.

7. The method of claim 6 further comprising generating an acoustic wave that propagates though a member that is coupled to the drillstring at the first and second locations and wherein the time delay depends upon the length and material properties of the member.

8. The method of claim 7 wherein the acoustic wave in the member is generated by a force that is equal and opposite to the first force.

9. The method of claim 8 wherein the member is rigidly attached to the drillstring at the second location.

10. The method of claim 9 wherein the member comprises a steel hollow shaft having a circular cross section and being positioned inside the drillstring.

11. The method of claim 7 wherein the first force and the acoustic wave in the member are generated using one or more electromagnetic actuators.

12. The method of claim 11 wherein the one or more electromagnetic actuators comprise one or more coils mounted to drillstring at the first location and one or more magnets mounted to the member.

13. The method of claim 1 wherein the drillstring is made primarily of steel, and wherein the relative movement in the drillstring between first location and the second location is due primarily to the elastic properties of the steel.

14. The method of claim 1 wherein the drillstring is a portion of drill collar.

15. The method of claim 1 further comprising the step of suppressing acoustic noise in the drillstring in a predetermined frequency band between the first location and the drill bit.

16. The method of claim 15 wherein the step of suppressing acoustic noise is accomplished using a device comprising adjacent zones of different acoustic impedances.

17. The method of claim 15 wherein the predetermined frequency band is a second pass band, and the forces imparted at the first and second locations generate acoustic signals within the second pass band.

18. The method of claim 1 further comprising the steps of: receiving acoustic signals at the surface that have been generated by imparting forces at the first and second locations; converting the acoustic signals into electromagnetic signals; and recording the electromagnetic signals.

19. The method of claim 1 wherein the first and second locations are in a bottom hole assembly.

20. The method of claim 1 wherein the first and second locations are a substantial distance from the bit, and tools in a bottom hole assembly communicate with a receiver near the first and second locations via a cable.

21. The method of claim 20 wherein the drill string is a portion of drill pipe adapted so as to create telemetry signals.

22. An apparatus for creating an acoustic signal on a drillstring located in a wellbore comprising: a length of drill string having a first location and a second location; and an elastic member coupled to the drill string so as to enable the application of a first force on the drillstring at the first location, and a second force on the drillstring at the second location, the first force and the second force being in opposite directions.

23. The apparatus of claim 22 wherein the first and second forces are torsional forces.

24. The apparatus of claim 22 wherein the first and second forces are axial forces .

25. The apparatus of claim 23 wherein the magnitude of the first and second forces are approximately equal .

26. The apparatus of claim 23 the member enables the application of third force on the drillstring at a third location, and the sum of forces applied to the drill string is substantially equal to zero.

27. The apparatus of claim 23 wherein the member is coupled to the drillstring at the first location with one or more electromagnetic actuators .

28. The apparatus of claim 27 wherein the member is coupled to the drillstring at the second location using a rigid attachment.

29. The apparatus of claim 28 wherein the one or more electromagnetic actuators comprise one or more coils mounted to drillstring at the first location and one or more magnets mounted to the member.

30. The apparatus of claim 29 wherein the member comprises a steel hollow shaft having a circular cross section and being positioned inside the drillstring.

31. The apparatus of claim 23 wherein the drillstring is made primarily of steel, and wherein the relative torsional movement in the drillstring between first location and the second location is due primarily to the elastic properties of the steel.

32. The apparatus of claim 23 further comprising a baffle located on the drillstring between the first location and the drill bit the baffle adapted and configured to suppress torsional waves in the drillstring in a predetermined frequency range.

33. The apparatus of claim 32 wherein the baffle comprises adjacent portions of material, each portion having a different acoustic impedance than each adjacent portion.

34. The apparatus of claim 33 wherein the predetermined frequency band is a second pass band, and the torsional forces imparted at the first and second locations generate torsional signals within the second pass band.