GB2421334A

GB2421334A - Communicating downhole measurements to the surface by modulating a carrier stimulus communicated through a downhole fluid

Info

Publication number: GB2421334A
Application number: GB0523481A
Authority: GB
Inventors: Songming Huang; Franck Monmont; Robert Tennent; Matthew R Hackworth; Craig D Johnson
Original assignee: Gemalto Terminals Ltd; Schlumberger Holdings Ltd
Current assignee: Gemalto Terminals Ltd; Schlumberger Holdings Ltd
Priority date: 2004-12-20
Filing date: 2005-11-18
Publication date: 2006-06-21
Anticipated expiration: 2025-11-18
Also published as: GB0523481D0; CA2527751C; CA2527751A1; GB2421334B

Abstract

In a subterranean well, a downhole measurement is communicated uphole by modulating a carrier stimulus communicated through a downhole fluid, e.g. water. For example, a pump system 140 may include a piston 141 and a drive unit 142 to generate acoustic waves within a liquid-filled column formed by annulus 130. A stop valve 161 modulates the acoustic waves by opening or blocking access to a volume 132 separated from the annulus 130 by packers 133, 134. In other examples, the downhole measurement may be a pressure associated with an isolated zone established by a zone isolation tool, or the measurement may be a slurry flow near a slurry exit port of a gravel packing tool, or the measurement may be a pressure of fracturing fluid measured during a fracturing operation.

Description

BOREHOLE TELEMETRY SYSTEM

BACKGROUND The present invention generally relates to a borehole telemetry system. One of the more difficult problems associated with any borehole is to communicate measured data between one or more locations down a borehole and the surface, or between down-hole locations themselves. For example, communication is desired by the oil industry to retrieve, at the surface, data generated down-hole during operations such as perforating, fracturing, and drill stem or well testing; and during production operations such as reservoir evaluation testing, pressure and temperature monitoring. Communication is also desired to transmit intelligence from the surface to down-hole tools or instruments to effect, control or modify operations or parameters. Accurate and reliable down-hole communication is particularly important when complex data comprising a set of measurements or instructions is to be communicated, i.e., when more than a single measurement or a simple trigger signal has to be communicated. For the transmission of complex data it is often desirable to communicate encoded digital signals. One approach which has been widely considered for borehole communication is to use a direct wire connection between the surface and the down-hole location(s). Communication then can be made via electrical signal through the wire. While much effort has been spent on "wireline" communication, its inherent high telemetry rate is not always needed and very often does not justify its high cost. Wireless communication systems have also been developed for purposes of communicating data between the surface of the well and a downhole tool. These techniques include, for example, communicating commands downhole via pressure pulses and fluid or acoustic communication, for example. A difficulty with some of these arrangements is that the communication is limited in scope and/or may require a relatively large amount of downhole power. Thus, there is a continuing need for a borehole telemetry system that addresses one or more of the problems that are stated above as well as possibly addresses one or more problems that are not stated forth above.

SUMMARY In an embodiment of the invention, a system that is usable with a subterranean well includes an assembly and a downhole telemetry tool. The assembly performs a downhole measurement. The telemetry tool modulates a carrier stimulus communicated through a well fluid to communicate the downhole measurement uphole. Advantages and other features of the invention will become apparent from the following description, drawing and claims.

BRIEF DESCRIPTION OF THE DRAWINGS Figs. 1, 2, 3A and 7A are schematic diagrams of borehole telemetry systems according to different embodiments of the invention. Fig. 3B is a schematic diagram of a resonator of the system of Fig. 3A according to an embodiment of the invention. Figs. 4A and 4B depict power spectra as received at a surface location with and without inference of the source spectrum, respectively according to an embodiment of the invention. Figs. 5A and 5B depict a technique to tune a telemetry system according to an embodiment of the invention. Fig. 6 depicts an element of a telemetry system having low power consumption according to an embodiment of the invention. Fig. 7B is a schematic diagram of an element of a downhole power source of the system of Fig. 7A according to an embodiment of the invention.Fig. 8 is a flow diagram depicting a borehole telemetry technique according to an embodiment of the invention. Fig. 9 is a schematic diagram of a borehole telemetry system that includes a packer setting tool according to an embodiment of the invention. Figs. 10 and 11 are schematic diagrams of borehole telemetry systems that include tools to set zonal isolation devices according to different embodiment of the invention. Fig. 12 is a schematic diagram of a borehole telemetry system that includes a gravel packing tool according to an embodiment of the invention. Fig. 13 is a schematic diagram of a borehole telemetry system that includes a straddle packer assembly according to an embodiment of the invention. Fig. 14 is a schematic diagram of a borehole telemetry system that includes a single trip perforation and fracturing service tool according to an embodiment of the invention.Fig. 15 is a schematic diagram of a borehole telemetry system that includes a formation isolation valve according to an embodiment of the invention.

DETAILED DESCRIPTION Referring first to the schematic drawing of Fig. 1, there is shown a cross-section through a cased wellbore 110 with a work string 120 suspended therein. Between the work string 120 and the casing 111 there is an annulus 130. During telemetry operations the annulus 130 is filled with a low-viscosity liquid such as water. A surface pipe 131 extends the annulus to a pump system 140 located at the surface. The pump unit includes a main pump for the purpose of filing the annulus and a second device that is used as an acoustic wave source. The wave source device includes a piston 141 within the pipe 131 and a drive unit 142. Further elements located at the surface are sensors 150 that monitor acoustic or pressure waveforms within the pipe 131 and thus acoustic waves traveling within the liquid-filled column formed by the annulus 130 and surface pipe 131. At a down-hole location there is shown a liquid filled volume formed by a section 132 of the annulus 130 separated from the remaining annulus by a lower packer 133 and an upper packer 134. The packers 133, 134 effectively terminate the liquid filled column formed by the annulus 130 and surface pipe 131. Acoustic waves generated by the source 140 are reflected by the upper packer 134. The modulator of the present example is implemented as a stop valve 161 that opens or blocks the access to the volume 132 via a tube 162 that penetrates the upper packer 134. The valve 161 is operated by a telemetry unit 163 that switches the valve from an open to a closed state and vice versa. The telemetry unit 163 in turn is connected to a data acquisition unit or measurement sub 170. The unit 170 receives measurements from various sensors (not shown) and encodes those measurements into digital data for transmission. Via the telemetry unit 163 these data are transformed into control signals for the valve 161. In operation, the motion of the piston 141 at a selected frequency generates a pressure wave that propagates through the annulus 130 in the down-hole direction. After reaching the closed end of the annulus, this wave is reflected back with a phase shift added by the down-hole data modulator and propagates towards the surface receivers 150. The data modulator can be seen as consisting of three parts: firstly a zero-phaseshift reflector, which is the solid body of the upper packer 134 sealing the annulus and designed to have a large acoustic impedance compared with that of the liquid filling the annulus, secondly a 180-degree phase shifting (or phase-inverting) reflector, which is formed when valve 161 is opened and pressure waves are allowed to pass through the tube 162 between the isolated volume 132 and the annulus 130 and thirdly the phase switching control device 162, 163 that enables one of the reflectors (and disables the other) according to the binary digit of the encoded data. In the example the phase-shifting reflector is implemented as a Helmholtz resonator, with a fluid-filled volume 132 providing the acoustic compliance, C, and the inlet tube 162 connecting the annulus and the fluid-filled volume providing an inertance, M, where [1] C=V/pc2 and [2] M=pL/a where V is the fluid filled volume 132, p and c are the density and sound velocity of the filling fluid, respectively, and L and a are the effective length and the cross-sectional area of the inlet tube 162, respectively. The resonance frequency of the Helmholtz resonator is then given by: [3] 0= 1/(MC)0 5 = c(a/(L V) )0.5 When the source frequency equals too, the resonator presents its lowest impedance at the down-hole end of the annulus. When the resonator is enabled, i.e., when the valve 161 is opened, its low impedance is in parallel with the high impedance provided by the upper packer 134 and the reflected pressure wave is phase shifted by approximately 180 degrees, and thus effectively inverted compared to the incoming wave. The value of 0 can range from a few Hertz to about 70 Hertz, although for normal applications it is likely to be chosen between 10 to 40Hz. The basic function of the phase switching control device, shown as units 163 and 161 in Fig. 1, is to enable and disable the Helmholtz resonator. When enabled, the acoustic impedance at the down-hole end of the annulus equals that of the resonator, and the reflected wave is phase-inverted.When disabled, the impedance becomes that of the packer, and the reflected wave has no phase change. If one assumes that the inverted phase represents binary digit "1", and no phase shift as digit "0", or vice versa, by controlling the switching device with the binary encoded data, the reflected wave becomes a BPSK (binary phase shift key) modulated wave, carrying data to the surface. The switching frequency, which determines the data rate (in bits/s), does not have to be the same as the source frequency. For instance for a 24Hz source (and a 24Hz resonator), the switching frequency can be 12Hz or 6Hz, giving a data rate of 12bit/s or 6-bit/s. The down-hole data are gathered by the measurement sub 170. The measurement sub 170 contains various sensors or gauges (pressure, temperature etc.) and is mounted below the lower packer 133 to monitor conditions at a location of interest.The measurement sub may further contain data-encoding units and/or a memory unit that records data for delayed transmission to the surface. The measured and digitized data are transmitted over a suitable communication link 171 to the telemetry unit 163, which is situated above the packer. This short link can be an electrical or optical cable that traverses the dual packer, either inside the packer or inside the wall of the work string 120. Alternatively it can be implemented as a short distance acoustic link or as a radio frequency electromagnetic wave link with the transmitter and the receiver separated by the packers 133, 134. The telemetry unit 163 is used to encode the data for transmission, if such encoding has not been performed by the measurement sub 170.It further provides power amplification to the coded signal, through an electrical power amplifier, and electrical to mechanical energy conversion, through an appropriate actuator. For use as a two-way telemetry system, the telemetry unit also accepts a surface pressure wave signal through a down-hole acoustic receiver 164. A two-way telemetry system can be applied to alter the operational modes of down-hole devices, such as sampling rate, telemetry data rate during the operation. Other functions unrelated to altering measurement and telemetry modes may include open or close certain down-hole valve or energize a down-hole actuator. The principle of down-hole to surface telemetry (up-link) has already been described in the previous sections.To perform the surface to down-hole down link, the surface source sends out a signal frequency, which is significantly different from the resonance frequency of the Helmholtz resonator and hence outside the up-link signal spectrum and not significantly affected by the down-hole modulator. For instance, for a 20Hz resonator, the down-linking frequency may be 39Hz (in choosing the frequency, the distribution of pump noise frequencies, mainly in the lower frequency region, need to be considered). When the down-hole receiver 164 detects this frequency, the down-hole telemetry unit 163 enters into a down-link mode and the modulator is disabled by blocking the inlet 162 of the resonator. Surface commands may then be sent down by using appropriate modulation coding, for instance, BPSK or FSK on the down-link carrier frequency. The up-link and down-link may also be performed simultaneously.In such case a second surface source is used. This may be achieved by driving the same physical device 140 with two harmonic waveforms, one up-link carrier and one down-link wave, if such device has sufficient dynamic performance. In such parallel transmissions, the frequency spectra of up and down going signals should be clearly separated in the frequency domain. The above described elements of the novel telemetry system may be improved or adapted in various ways to different down hole operations. In the example of Fig 1, the volume 132 of the Helmholtz resonator is formed by inflating the lower main packer 133 and the upper reflecting packer 134, and is filled with the same fluid as that present in the column 130. However as an alternative the Helmholtz resonator may be implemented as a part of dedicated pipe section or sub.For example in Fig. 2, the phase-shifting device forms part of a sub 210 to be included into a work string 220 or the like. The volume 232 of the Helmholtz resonator is enclosed between a section of the work string 220 and a cylindrical enclosure 230 surrounding it. Tubes 262a,b of different lengths and/or diameter provide openings to the wellbore. Valves 261a,b open or close these openings in response to the control signals of a telemetry unit 263. A packer 234 reflects the incoming waves with phase shifts that depend on the state of the valves 261 a,b. The volume 232 and the inlet tubes 262a,b are shown pre-filled with a liquid, which may be water, silicone oil, or any other suitable low-viscosity liquid. Appropriate dimensions for inlet tubes 262 and the volume 232 can be selected in accordance with equations [1] - [3] to suit different resonance frequency requirements.With the choice of different tubes 262a,b, the device can be operated at an equivalent number of different carrier wave frequencies. In the following example the novel telemetry system is implemented as a coiled tubing unit deployable from the surface. Coiled tubing is an established technique for well intervention and other operations. In coiled tubing a reeled continuous pipe is lowered into the well. In such a system the acoustic channel is created by filling the coiled tubing with a suitable liquid. Obviously the advantage of such a system is its independence from the specific well design, in particular from the existence or nonexistence of a liquid filled annulus for use as an acoustic channel. A first variant of this embodiment is shown in Fig. 3. In Fig. 3A, there is shown a borehole 310 surrounded by casing pipes 311.It is assumed that no production tubing has been installed. Illustrating the application of the novel system in a well stimulation operation, pressurized fluid is pumped through a treat line 312 at the well head 313 directly into the cased bore hole 310. The stimulation or fracturing fluid enters the formation through the perforation 314 where the pressure causes cracks allowing improved access to oil bearing formations. During such a stimulation operation it is desirable to monitor locally, i.e., at the location of the perforations, the changing wellbore conditions such as temperature and pressure in real time, so as to enable an operator to control the operation on the basis of improved data. The telemetry tool includes a surface section 340 preferably attached to the surface end 321 of the coiled tubing 320.The surface section includes an acoustic source unit 341 that generates waves in the liquid filled tubing 320. The acoustic source 341 on surface can be a piston source driven by electro-dynamic means, or even a modified piston pump with small piston displacement in the range of a few millimeters. Two sensors 350 monitor amplitude and/or phase of the acoustic waves traveling through the tubing. A signal processing and decoder unit 351 is used to decode the signal after removing effects of noise and distortion, and to recover the down-hole data. A transition section 342, which has a gradually changing diameter, provides acoustic impedance match between the coiled tubing 320 and the instrumented surface pipe section 340. At the distant end 323 of the coiled tubing there is attached a monitoring and telemetry sub 360, as shown in detail in Fig. 3B.The sub 360 includes a flow-through tube 364, a lower control valve 365, down-hole gauge and electronics assembly 370, which contains pressure and temperature gauges, data memory, batteries and an additional electronics unit 363 for data acquisition, telemetry and control, a liquid volume or compliance 332, a throat tube 362 and an upper control/modulation valve 361 to perform the phase shifting modulation. The electronic unit 363 contains an electromechanical driver, which drives the control/modulation valve 361. In case of a solenoid valve, the driver is an electrical one that drives the valve via a cable connection. Another cable 371 provides a link between the solenoid valve 365 and the unit 363.The coiled tubing 320, carrying the down-hole monitoring/telemetry sub 360, is deployed through the well head 313 by using a tubing reel 324, a tubing feeder 325, which is mounted on a support frame 326. Before starting data acquisition and telemetry, both valves 361, 365 are opened, and a low attenuation liquid, e.g. water, is pumped through the coiled tubing 320 by the main pump 345, until the entire coiled tubing and the liquid compliance 332 are filled with water. The lower valve 365 is then shut maintaining a water filled continuous acoustic channel. Ideally the down-hole sub is positioned well below the perforation to avoid high speed and abrasive fluid flow. The liquid compliance (volume) 332 and the throat tube 362 together form a Helmholtz resonator, whose resonance frequency is designed to match the telemetry frequency from the acoustic source 341 on the surface.The modulation valve 361, when closed, provides a high impedance termination to the acoustic channel, and acoustic wave from the surface is reflected at the valve with little change in its phase. When the valve is open, the Helmholtz resonator provides a low termination to the channel, and the reflected wave has an added phase shift of close to 180[deg]. Therefore the valve controlled by a binary data code will produce an up-going (reflected) wave with a BPSK modulation. After the stimulation job, the in-well coiled tubing system can be used to clean up the well. This can be done by opening both valves 361, 362 and by pumping an appropriate cleaning fluid through the coiled tubing 320. Coiled tubing system, as described in Fig. 3, may also be used to establish a telemetry channel through production tubing or other down-hole installations.In the above examples of the telemetry system the reflected signals monitored on the surface are generally small compared to the carrier wave signal. The reflected and phase-modulated signal, due to the attenuation by the channel, is much weaker than this background interference. Ignoring the losses introduced by the non-ideal characteristics of the down-hole modulator, the amplitude of the signal is given by: [4] Ar = As10-2 L/20 where Ar and As are the amplitudes of the reflected wave and the source wave, both at the receiver, a is the wave attenuation coefficient in dB/Kft and 2L is the round trip distance from surface to down-hole, and then back to the surface. Assuming a water filled annulus with =1dB/kft at 25Hz, then for a well of lOkft depth, then Ar =0.1 As, or the received wave amplitude is attenuated by 20dB compared with the source wave. The plot shown in Fig. 4A shows a simulated receiver spectrum for an application with l Okft water filled annulus. A carrier and resonator frequency of 20Hz is assumed. The phase modulation is done by randomly switching (at a frequency of l OHz) between the reflection coefficient of a down-hole packer (0.9) and that of the Helmholtz resonator (-0.8). The effect is close to a BPSK modulation.The background source wave (narrow band peak at 20Hz) interferes with the BPSK signal spectrum which is shown in Fig. 4B. Signal processing can be used to receive the wanted signal in the presence of such a strong sinusoidal tone from the source. A BPSK signal v(t) can be described mathematically as follows [5] v(t) = d(t)Av cos( ct) where d(t) E {+ 1,-1} = binary modulation waveform Av = signal amplitude and c = radian frequency of carrier wave. The source signal at the surface has the form sensor 1538 for purposes of measuring a pressure in the annulus 1504. Thus, the pressure sensors 1536 and 1538 are used for measuring pressures above the formation isolation valve 1548.The formation isolation valve assembly 1530 may also include, for example, a pressure sensor 1539 for purposes of measuring a pressure inside the central passageway 1503 below the formation isolation valve 1548; and the formation isolation valve assembly 1530 may include a pressure sensor 1540 for purposes of measuring the pressure in an annulus 1505 located below the packer 1506. Thus, the pressure sensors 1539 and 1540 may be used for purposes of measuring pressures below the formation valve 1548. While the present invention has been described with respect to a limited number of embodiments, those skilled in the art, having the benefit of this disclosure, will appreciate numerous modifications and variations therefrom. It is intended that the appended claims cover all such modifications and variations as fall within the true spirit and scope of this present invention.

Claims

1. A method usable in a subterranean well, the method comprising: performing a downhole measurement; and modulating a carrier stimulus communicated through a downhole fluid to communicate the downhole measurement uphole.

2. The method of claim 1, wherein the downhole measurement comprises a measurement indicative of a change in state of a downhole tool.

3. The method of claim 1, wherein the act of modulating is used to confirm operation of a downhole tool.

4. The method of claim 1, further comprising receiving a second stimulus at the surface of the well indicative of the measurement.

5. The method of claim 1, wherein the act of performing occurs in response to setting a packer.

6. The method of claim 5, wherein the measurement indicates an integrity of an annulus seal formed by the packer when set.

7. The method of claim 5, wherein the measurement comprises a pressure of a fluid through which pressure is communicated to set the packer.

8. The method of claim 5, further comprising forming a sealed annulus in response to setting the packer and using the annulus to communicate the second stimulus.

9. The method of claim 1, wherein the act of performing occurs in response to setting a zone isolation tool.

10. The method of claim 9, wherein the measurement comprises a pressure inside an isolated zone established by the zone isolation tool.

11. The method of claim 9, wherein the measurement comprises a pressure below an isolated zone established by the zone isolation tool.

12. The method of claim 9, wherein the measurement comprises a pressure above an isolated zone established by the zone isolation tool.

13. The method of claim 1, wherein the act of performing occurs in response to a gravel packing operation.

14. The method of claim 13, wherein the measurement comprises a pressure of a slurry flow near a slurry exit port of a gravel packing tool where the slurry flow exits the tool and enters an annulus of the well.

15. The method of claim 13, further comprising communicating a wireless stimulus downhole to change a state of a gravel packing tool.

16. The method of claim 1, wherein the act of performing comprises setting a seal assembly to isolate a zone and the measurement comprises a pressure in the zone.

17. The method of claim 16, wherein the modulating generates a second stimulus that indicates the measurement and is generated over a first time interval that has a substantially longer duration than a second time interval over which the downhole measurement occurs.

18. The method of claim 16, further comprising triggering the measurement in response to a predetermined pressure level caused by at least one of a shut-in condition and a draw-down condition.

19. The method of claim 1, wherein the act of performing comprises measuring a pressure associated with a fracturing operation.

20. The method of claim 19, wherein the pressure comprises a pressure of fracturing fluid during pumping of the fracturing fluid.

21. The method of claim 19, wherein the pressure comprises a pressure of fracturing fluid during flowback of the fracturing fluid after pumping of the fracturing fluid.

22. The method of claim 1, wherein the measurement comprises a pressure near a permanently mounted formation isolation valve.

23. The method of claim 22, wherein the pressure comprises a pressure below the valve in an area of the well sealed off by the valve.

24. The method of claim 22, wherein the pressure comprises a pressure above the valve in a region of the well isolated from the region by the valve.

25. A system usable with a subterranean well, the system comprising: an assembly to perform a downhole measurement; and a downhole telemetry tool connected to the assembly to modulate a carrier stimulus communicated through a downhole fluid to communicate the downhole measurement uphole.

26. The system of claim 25, wherein the downhole measurement comprises a measurement indicative of a change in a state of the assembly.

27. The system of claim 25, wherein the telemetry tool generates the second stimulus to confirm operation of the assembly.

28. The system of claim 25, wherein the telemetry tool generates a second stimulus that is received at the surface of the well and indicates the measurement.

29. The system of claim 25, wherein the assembly comprises a packer.

30. The system of claim 29, wherein the measurement indicates an integrity of an annulus seal formed by the packer.

31. The system of claim 29, wherein the packer is adapted to be set in response to a pressure of a fluid and the measurement is indicative of the pressure.

32. The system of claim 29, wherein setting of the packer creates a sealed annulus in which the assembly generates the second stimulus.

33. The system of claim 25, wherein the assembly comprises a zone isolation tool adapted to establish an isolated zone downhole in the well.

34. The system of claim 33, wherein the measurement comprises a pressure inside the isolated zone.

35. The system of claim 33, wherein the measurement comprises a pressure below the isolated zone.

36. The system of claim 33, wherein the measurement comprises a pressure above the isolated zone.

37. The system of claim 25, wherein the assembly comprises a gravel packing tool.

38. The system of claim 37, wherein the gravel packing tool comprises an exit port to communicate a slurry flow inside an annulus of the well and a sensor to measure a pressure of the slurry flow near the exit port.

39. The system of claim 37, wherein the gravel packing tool is adapted to change a state in response to a wireless stimulus communicated downhole from the surface of the well.

40. The system of claim 25, wherein the assembly comprises a straddle packer assembly to isolate a zone in the well.

41. The system of claim 40, wherein the measurement is indicated by a second stimulus and the second stimulus is generated over a first time interval that has a substantially longer duration than a second time interval over which the assembly performs the downhole measurement.

42. The system of claim 40, wherein the assembly is adapted to trigger the measurement in response to a predetermined pressure level caused by at least one a shut-in condition and a draw-down condition in the zone.

43. The system of claim 25, wherein the assembly comprises a tool to communicate a fracturing fluid into the well.

44. The system of claim 43, wherein the assembly comprises a sensor to measure a pressure of fracturing fluid during pumping of the fracturing fluid through the tool.

45. The system of claim 43, wherein the assembly comprises a sensor to measure a pressure of fracturing fluid during flowback of the fracturing fluid after pumping of the fracturing fluid through the tool.

46. The system of claim 43, wherein the assembly further includes a perforating gun.

47. The system of claim 25, wherein the assembly comprises a permanently mounted formation isolation valve.

48. The system of claim 47, wherein the assembly comprises a sensor to measure a pressure below the valve in an area of the well sealed off by the valve.

49. The system of claim 47, wherein the assembly comprises a sensor to measure a pressure in a region above the valve and isolated by the valve from a formation below the valve.