US20090034368A1

US20090034368A1 - Apparatus and method for communicating data between a well and the surface using pressure pulses

Info

Publication number: US20090034368A1
Application number: US11/833,066
Authority: US
Inventors: Michael H. Johnson
Original assignee: Baker Hughes Inc
Current assignee: Baker Hughes Holdings LLC
Priority date: 2007-08-02
Filing date: 2007-08-02
Publication date: 2009-02-05
Also published as: WO2009018420A3; WO2009018420A2; CA2693485A1

Abstract

In one aspect, wellbore apparatus is disclosed that includes a conduit that contains a non-circulating liquid therein and is configured to be placed in a well, and a transmitter that is configured to transmit pressure pulses through the liquid in the conduit. In another aspect, a method is disclosed that includes placing a conduit in the wellbore that is closed at one end and contains a liquid medium therein, and transmitting information in the form of pressure pulses through the liquid medium in the conduit.

Description

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure
This disclosure relates to apparatus and methods for communicating data between a well and the surface.
2. Background Information
Wells (also referred to as “wellbores” or “boreholes”) are drilled and completed to produce hydrocarbons (oil and gas) from one or more production zones penetrated by a wellbore. A typical completed well may include a metallic casing that lines the well. Cement is generally placed between the casing and the well to provide a seal between the formation surrounding the well and the casing. Perforations made in the formation through the casing at selected locations across from the producing formations (also referred to as the “production zones” or “reservoirs”) allow the formation fluid containing the hydrocarbons to flow into the cased well. The formation fluid flows to the surface via a production tubing placed inside the casing because the pressure in the production zone is generally higher than the pressure caused by the weight of the fluid column in the well. An artificial lift mechanism, such as an electrical submersible pump (“ESP”) or a gas-lift mechanism is often employed when the formation pressure is not adequate to push the fluid in the well to the surface.
A variety of devices are used in the well to control the flow of the fluid from the production zones to optimize the oil and gas production over the life of the well. Remotely-controlled flow control valves and chokes are often used to control the flow of the fluid. Chemicals are injected at certain locations in the well via one or more tubes that run from the surface to the production zones to inhibit the formation of harmful chemicals, such as corrosion, hydrate, scale, hydrogen sulfide, methane, asphaltene, etc. A number of sensors are typically placed in the well to provide information about a variety of downhole parameters, including the position of the valves and chokes, pressure, temperature, fluid flow rate, acoustic signals responsive to water front and surface or downhole induced signals in the subsurface formations, resistivity, porosity, permeability, water-cut, etc. The measurement data is typically transmitted to the surface via conductors, such as electrical wires, that run from the surface to selected locations in the well. Signals are also sent from the surface to the downhole sensors and devices via such conductors to control their operations. Such conductors can degrade over time or become non-functional. It is therefore desirable to have a data communication system that may be less prone to degradation.
The present disclosure provides improved apparatus, systems and methods for communicating data between a well and the surface.

SUMMARY

In one aspect, a method is disclosed that includes: placing a conduit containing non-circulating liquid therein in a well; and generating pressure pulses through the liquid in the tubing to transmit information between a location in the well and the surface. The system may further include one or more repeaters that detect pressure pulses in the conduit and transmit pressure pulses through the liquid in the conduit that correspond to the detected pressure pulses.
In another aspect, a well data communication system is disclosed that includes: a conduit which extends from a downhole location to an uphole location and a transducer that is configured to send information through the liquid medium in the form of pressure pulses. A detector spaced from the transducer detects the pulses in the conduit.
In another aspect, an apparatus is disclosed for use in a well that includes: a conduit that has a liquid medium therein, which conduit is configured to be deployed in the well; and a transducer that is configured to generate pressure pulses through the liquid medium in the conduit to transmit data signals.
Examples of the more important features of a well data communication system and methods have been summarized rather broadly in order that the detailed description thereof that follows may be better understood, and in order that the contributions to the art may be appreciated. There are, of course, additional features that will be described hereinafter and which will form the subject of the claims. The summary is provided to provide the reader with broad information and is not intended to be used in any way to limit the scope of the claims.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the apparatus, systems and methods for communicating information between a well and the surface, reference should be made to the following detailed description, taken in conjunction with the accompanying drawings, in which like elements generally have been given like numerals, wherein:

FIG. 1A shows a schematic diagram of an exemplary well configured to provide data communication between devices in the well and a surface controller according to one embodiment of the disclosure;

FIG. 1B shows a schematic diagram of certain controllers and devices at the surface that may be utilized to establish data communication between the well and the surface; and

FIG. 2 shows a functional block diagram of a transducer that may be utilized to generate pressure pulses in a well system to establish data communication between a well and the surface, such as shown in FIGS. 1 and 2.

DETAILED DESCRIPTION

FIGS. 1A and 1B (collectively referred to herein as “FIG. 1”) collectively show schematic diagrams of an exemplary embodiment of a well system 100 that includes a data communication system between a completed well 50 and the surface 112 according to one embodiment of the disclosure. FIG. 1A shows the schematic diagram of the equipment of the well system 100 that is below the surface 112, while FIG. 1B shows the functional block diagram of exemplary equipment of the well system 100 that may be deployed at the surface 112 to manage the operations of the system 100. The system 100 shows the well 50 formed in a formation 55 that produces formation fluids 56 a and 56 b (such as hydrocarbons) from two exemplary production zones 52 a (upper production zone) and 52 b (lower production zone) respectively. The well 50 is shown lined with a casing 57 containing perforations 54 a, adjacent the upper production zone 52 a and perforations 54 b adjacent the lower production zone 52 b. A packer 64, which may be a retrievable packer, positioned above or uphole of the lower production zone perforations 54 a isolates the lower production zone 52 b from the upper production zone 52 a. A screen 59 b adjacent to the perforations 54 b may be installed to prevent or inhibit solids, such as sand, from entering into the wellbore from the lower production zone 54 b. Similarly, a screen 59 a may be used adjacent the upper production zone perforations 59 a to prevent or inhibit solids from entering into the well 50 from the upper production zone 52 a.
Formation fluid 56 b from the lower production zone 52 b enters the annulus 51 a of the well 50 through the perforations 54 a and into a tubing 53 via a flow control valve 67. The flow control valve 67 may be a remotely controlled sliding sleeve valve or any other suitable valve or choke that is configured to regulate the flow of the fluid from the annulus 51 a into the production tubing 53. An adjustable choke 40 in the tubing 53 may be used to regulate the fluid flow from the lower production zone 52 b to the surface 112. The formation fluid 56 a from the upper production zone 52 a enters the annulus 51 b (the annulus portion above the packer 64) via perforations 54 a. The formation fluid 56 a enters production tubing or line 45 via inlets 42. An adjustable valve or choke 44 regulates the fluid flow into the tubing 45. Each valve, choke and other such device in the well may be operated electrically, hydraulically, mechanically and/or pneumatically by a surface control unit, such as controller 150 and/or by a downhole control unit or controller, such as controller 60. The fluid from the upper production zone 52 a and the lower production zone 52 b enter the line 46.
When the formation pressure is not sufficient to push the fluid 56 a and/or fluid 56 b to the surface, an artificial lift mechanism, such as an electrical submersible pump (ESP), gas lift system or other desired systems may be utilized to lift the fluids from the well 50 to the surface 112. In the system 100, an ESP 30 in a manifold 31 is shown as the artificial lift mechanism, which receives the formation fluids 56 a and 56 b and pumps such fluids via tubing 47 to the surface 112. A cable 134 provides power to the ESP 30 from a surface power source 132. The cable 134 also may include two-way data communication links 134 a and 134 b (FIG. 1B), which may include one or more electrical conductors or fiber optic links to provide two-way signals and data communication between the ESP 30, ESP sensors SE and an ESP control unit 130 (FIG. 1B).
Still referring to FIGS. 1A and 1B, in one aspect, a variety of sensors are placed at suitable locations in the well 50 to provide measurements or information relating to a number of downhole parameters of interest. In one aspect, one or more gauge or sensor carriers, such as a carrier 15, may be placed in the production tubing to house any number of suitable sensors. The carrier 15 may include one or more temperature sensors, pressure sensors, flow measurement sensors, resistivity sensors, sensors that may provide information about density, viscosity, water content or water cut, etc., and chemical sensors that provide information about scale, corrosion, hydrate, paraffin, hydrogen sulfide, emulsion, asphaltene, etc. Density sensors may provide fluid density measurements for fluid produced from each production zone and that of the combined fluid from two or more production zones. The resistivity sensor or another suitable sensor may provide measurements relating to the water content or the water-cut of the fluid mixture received from each production zones and/or the combined fluid. Other sensors may be used to estimate the oil/water ratio and gas/oil ratio for each production zone and for the combined fluid. The temperature, pressure and flow sensors provide measurements for the pressure, temperature and flow rate of the fluid in the line 53. Additional gauge carriers may be used to obtain one or more of the above-noted and other measurements relating to the formation fluid received from the upper production zone 52 a. Additional downhole sensors may be used at other desired locations to provide measurements relating to the presence and extent of chemicals downhole. Additionally, sensors S₁-S_mmay be permanently installed in the wellbore 50 to provide acoustic, seismic or microseismic measurements, formation pressure and temperature measurements, resistivity measurements and measurements relating to the properties of the casing 51 and formation 55. Such sensors may be installed in the casing 57 or between the casing 57 and the formation 55. Microseismic and other sensors may be used to detect water fronts, which may aid in making adjustments to the flow rates for each zone, chemical injection rate, ESP frequency, etc. Pressure and temperature changes or expected changes may provide early warning of changes in the chemical composition of the production fluid. Additionally, the screen 59 a and/or screen 59 b may be coated with tracers that are released due to the presence of water, which tracers may be detected at the surface or downhole to determine or predict the occurrence of water breakthrough. ESP sensors SE may include sensors that provide information about temperature, pressure and flow rate of the ESP, differential pressure across the ESP, ESP frequency, power, etc. Sensors also may be provided at the surface, such as a sensor for measuring the water content in the received fluid, total flow rate for the received fluid, fluid pressure at the wellhead, temperature, etc. Other devices may be used to estimate the production of sand for each zone.
In general, sufficient sensors may be suitably placed in the well 50 to obtain measurements relating to each desired parameter of interest. Such sensors may include, but are not limited to: sensors for measuring pressures corresponding to each production zone, pressure along the wellbore, pressure inside the tubing carrying the formation fluid, pressure in the annulus; sensors for measuring temperatures at selected places along the wellbore; sensors for measuring fluid flow rates corresponding to each of the production zones, total flow rate, flow through the ESP; sensors for measuring ESP temperature and pressure; chemical sensors for providing signals relating to the presence and extent of chemicals, such as scale, corrosion, hydrates, paraffin, emulsion, hydrogen sulfide and asphaltene; acoustic or seismic sensors that measure signals generated at the surface or in offset wells and signals due to the fluid travel from injection wells or due to a fracturing operation; optical sensors for measuring chemical compositions and other parameters; sensors for measuring various characteristics of the formations surrounding the well, such as resistivity, porosity, permeability, fluid density, etc. The sensors may be installed in the tubing in the well or in any device or may be permanently installed in the well. For example, sensors may be installed in the wellbore casing, in the wellbore wall or between the casing and the wall. The sensors may be of any suitable type, including electrical sensors, mechanical sensors, piezoelectric sensors, fiber optic sensors, optical sensors, etc. The signals from the downhole sensors may be partially or fully processed downhole, such as by a controller 60 that includes a microprocessor and associated electronic circuitry that is in signal or data communication with the downhole sensors and devices, and then communicated to the surface controller 150 (FIG. 1B) via a signal/data link, such as link 101. The signals from downhole sensors may also be sent directly to the surface controller 150.
A variety of hydraulic, electrical and data communication lines (collectively designated by numeral 20 (FIG. 1A) are run inside the well 50 to operate the various devices in the well 50 to obtain measurements and other data from the various sensors in the well 50 and to provide power and data communication between the surface and downhole equipment. As an example, a tube or tubing 21 may supply or inject a particular chemical from the surface into the fluid 56 b via a mandrel 36. Similarly, a tubing 22 may supply or inject a particular chemical to the fluid 56 a in the production tubing via a mandrel 37. Separate lines may be used to supply the additives at different locations in the well 50 or to supply different types of additives. Lines 23 and 24 may operate the chokes 40 and 44 and may be used to operate any other device, such as the valve 67. Lines 25 may provide electrical power to certain devices downhole from a suitable surface power source. Two-way data communication between downhole sensors, devices located at any one or more suitable downhole locations and a downhole controller, such as a controller 60 and/or one or more transducers, such as a transducer 110, may be established by any desired method, including, but not limited to, wires, optical fibers, acoustic telemetry using a fluid line, electromagnetic telemetry, optical fibers, wirelessly, etc.
In one aspect, one or more conduits or tubings, such as tubings 101 and 102 are placed or run between a suitable location in the well 50 and the surface 112 to establish data communication using pressure pulses through a liquid medium in the tubings 101 and/or 102 through. The tubings may be enclosed at a downhole end and may also be enclosed at the uphole or surface end. Additionally, the tubings include a suitable non-circulating liquid, such as water, oil, etc., which is suitable for sending pressure pulses therethrough. The tubings 101, 102 may be made from any suitable material, such as an alloy or a composite material capable of withstanding the downhole environment for an extended time period. Tubing 102 may be same or similar to the tubing 101. In FIG. 1, tubing 101 is shown in fluid communication with a downhole transducer 110, which may include any device that is configured to generate pressure pulses in the liquid medium in the tubing 101. The transducer 110 may include a receiver that receives signals or data from one or more sensors, such a sensors S₁-S_min the well 50 and other devices, such as a sensors that provide signals relating to the position of the sleeve 53, ESP operating parameters, such a flow rate through the ESP, and pump speed, etc. Such data or signals may be provided to the transducer 110 via any suitable data link, such as electrical conductors, optical fibers or wireless links. The transducer may be an active device that include a processor, memory and other circuitry that are configured to receive signals from one or more sensors and devices, process the received signals and transmit the processed signals as pressure signals through the liquid medium in the tubing 101. The processor may use any telemetry scheme, including but not limited to, amplitude, frequency, phase, pulse duration, pulse shape, time between the pulses or any combination thereof. A second transducer 120 spaced from the transducer 110 detects or receives the pressure pulses and sends the received signals to a surface controller or control unit, such as the central controller 150. The second transducer may include any suitable detector for detecting pressure pulses, such as a pressure sensor. The surface controller 150 decodes the signals received from the receiver 120 (FIG. 1B) and uses the signals to manage one or more operations of the well system 10. The surface controller may send data signals to the transducer 120, which transmits the received signals via the liquid media in the tubing 101 in the form of pressure pulses. Alternatively, a separate transducer 122 and tubing 102 may be used to send pressure pulses from the surface 112 to a downhole controller 60 via the liquid medium in the tubing 102. Each of the transducers 110 and 120 may be configured to generate the pressure pulses at multiple frequencies. The pressure pulses may be coded signals and may use any desired signals modulation technique, such as amplitude, phase, frequency, shape, pulse duration, time between pulses modulation or any combination thereof. Any suitable device may be used to generate pressure pulses, including but not limited to, a piezoelectric device, a poppet-type pulser, an oscillating-type or shear-wave pulser a rotary-type pulser or another suitable pulser.
Wells can be very long and can extend to several thousand meters. In some such wells, the pressure pulses transmitted by a transducer, such a transducer 110 may attenuate and may not be detectable by the receiver 120. In other cases, it may be desirable to transmit pressure pulses between branch wellbores and the surface or a branch wellbore and a main wellbore via the fluid-filled conduit and the signals may attenuate to an undesirable extent. Also, the transducer 110 over time may not be able to send signals that are strong enough to reach the receiver 120. In any such case, one or more additional transducers 110 or repeaters, such as R₁-R_n(generally designated by numeral 114), may be deployed in the well 50 and configured to detect signals from the conduit medium and retransmit the detected signals to the next repeater and/or the receiver 120. Similar transducers and repeaters may be deployed in the second conduit 102.
Each of the transducers, such as transducer 110, 120 and/or the repeaters R₁-R_n, may be an autonomous device. FIG. 2 shows a functional diagram of an autonomous transducer or repeater 200 according to one embodiment of the disclosure. The device 200 may include: a processor 210, such as a micro-controller, microprocessor or another suitable circuit combination; a data storage device or memory device 212, such a solid state memory device (Read-only-memory “ROM,” random access memory (“RAM”, flash memory, etc.) that is suitable for downhole application; and one or more computer programs or sets of instructions 214 that may be stored in the memory 212 and are accessible to the processor 210. The processor 210 communicates with the memory 212 and the programs 214 via links 211 and 213 respectively. A power source 220 provides power to the processor 210 as shown by link 221 and to the other components of the device 200 via link 223. In operation, signals T₁-T_pfrom sensors and other devices may be received by an interface 230. The interface 230 may be configured to condition the received signals, such as by amplifying and digitizing the signals. The processor 210 processes the signals from the interface 230, such as by sequencing the signals, putting the signals in appropriate data packets, assigning addresses of the sensors or the devices from which such signals were received by the interface 230, etc. and sends such processed signals via link 241 to a pulser (transmitter) 240 that sends the signals via the medium in the conduit as pressure pulses. The pressure pulses sent from the surface via the conduits 101 and/or 102 are received by a receiver or detector 245, which may condition the received signals and provide them to the processor 210. The processor 210 processes the surface-sent signals and may control one or more downhole devices 260 or send these signals to the downhole controller 60. The processor 210 may store any information in the memory device 212 and/or programs 214 to perform one or more of the functions described herein. The processor 210 is shown to communicate with the receiver 245 via link 243 and with downhole devices 260 via link 261. Thus in operation, the downhole transducer 110 receives signals from one or more devices or sensors in the well and transmits signals representative of the received signals as pressure pulses through a liquid-filled conduit placed in the well. A receiver spaced from the downhole transducer detects the pressure pulses and retransmits them to a surface controller for further use. The surface controller may send signals in the form of pressure pulses or by any other method to a downhole receiver via the same or a separate liquid-filled conduit. One or more repeaters may be provided along the liquid-filled tubing's to retransmit the pressure pulses.
Referring back to FIG. 1B, in one aspect, the exemplary equipment shown in FIG. 1B may be utilized to manage and control the various operations of the well system 10 in response to the signals received from the downhole transducer 110. In one aspect, the controller 150 may manage injection of additives from a chemical injection unit 120 into the well 50 to enhance production from one or more zones in response to the signals received from a chemical sensor that may provide information about the presence of certain chemicals, such as scale, hydrate, corrosion, asphaltene, hydrogen sulfide, etc. or in response to a water-cut sensor, resistivity sensor, etc.
In another aspect, the central controller 150 may control the operation of one or more downhole devices directly or via a downhole device control unit 160 by sending commands via a link 161. The commands may be instructions to alter the position of a choke or a sliding sleeve, etc and such commands may be in response to signals received from one or more downhole devices or sensors and/or signals received from a remote controller, such as controller 185 that may communicate with the controller 150 via a suitable link 189, such as Ethernet, the Internet, etc. The downhole device controller 160 may control the downhole devices via links 21-25. In another aspect, the central controller 150 may control the operation of the ESP 30 directly or via an ESP controller 130. The ESP controller may control power to the ESP from a power source 132 in response to the signals received from the ESP sensors and/or signals received from the central controller 150.
Thus, in one aspect, a system for communicating information between at least one location in a well and the surface is disclosed, wherein the system includes: a conduit that filled with a non-circulating liquid and a transducer that generates pressure pulses representative of signals to be transmitted through the conduit. A detector spaced from the transducer detects the pressure pulses in the conduit and generates electrical signals representative of the detected pressure pulses.
The transducer may include a pulser that generates the pressure pulses in the liquid in the conduit. The pulser may be any suitable device that is configured to generate the pressure pulses downhole, including but not limited to: a piezoelectric device that generates acoustic signals to generate the pressure pulses; a poppet-type pulser that includes a reciprocating piston or valve that obstructs fluid flow to generate pressure pulses; a shear-wave pulser that generates pressure pulses when a disc oscillates proximate a stationary disc to obstruct fluid flow; a rotary pulser that generates pressure pulses when a disc rotates proximate a stationary to obstruct a fluid flow.
In another aspect, the system may include one or more repeaters uphole of the transducer that detects the pressure pulses generated by the transducer. The repeater may condition the detected pressure pulses and generate the conditioned pulses through the liquid medium in the conduit. The uphole location may be in the well or at the surface. The system may further include a surface transducer that generates pressure pulses in a liquid-filled conduit to a downhole location and a detector downhole that detects the pressure pulses sent from the surface. The downhole detector may provide signals corresponding to the detected pulses to a downhole controller or processor. In one aspect, the transducer and/or any of the repeaters may be an autonomous device, which may include: a receiver that receives signals from at least one sensor; a processor that converts the signals received from the at least one sensor into coded signals; and a pulser that generates pressure pulses in the liquid corresponding to the coded signals. The system, in another aspect, may further include an interface that receives signals from at least one sensor or device in the well. The sensor or device may be one or more of: (i) a pressure sensor; (ii) a temperature sensor; (iii) an acoustic sensor; (iv) a flow rate measuring device; (v) a water-cut measurement device; (vi) a resistivity measuring device; (vii) a chemical detection sensor; (viii) a fiber optic sensor; (ix) a piezoelectric sensor; and (x) a density sensor.
The uphole location in the system may be a location in a branch wellbore, a main wellbore, a location at the surface of the earth, a location at the sea bed, a location on a land rig or a location on an offshore vessel or platform. The downhole sensors or devices may send signals to the transducer or a downhole controller via any suitable connection, including, but not limited to, electrical conductors, optical fibers and wireless links.
A suitable power source in the well or at the surface may provide power to the downhole transducers and repeaters, which may include: a battery; (ii) a power generation unit that generates electrical power in the wellbore; and (iii) a power unit at the surface that supplies electrical power via an electrical conductor disposed in or along the conduit. The conduit may conduit may be placed: (i) inside a production tubing carrying fluid to the surface; (ii) between a production tubing and a casing; or (iii) between a casing and formation surrounding the wellbore.
In another aspect, the system may include a plurality of sensors distributed in the well, and wherein the system may include a plurality of transducers, each of which receives signals from an associated sensor or device and transmits coded signals as pressure pulses through the liquid in the conduit that are representative of the received signals.
In another aspect, the system may include an additional liquid-filled conduit that is used to transmit pressure pulses from the surface to a downhole location. Alternatively, the system may include another telemetry system for transmitting signals from the surface, such an electro-magnet telemetry system, an acoustic telemetry system, wire in a tubing, etc. Additionally, each transducer and/or repeater may be an autonomous device and may include: an electronics module; and an energy source. The electronic module may further include a processor that acts according to programmed instructions for controlling an operation of the transducer. The energy source may be: (i) a battery; (ii) a thermoelectric generator; (iii) a combination of a battery and a thermoelectric generator; or (iv) a source at the surface. The transducers and repeaters may transmit signals at different frequencies and at more than one frequency. Additionally, the one or more sensors associated with the transducer or repeater may detect at least one parameter of interest related to: (i) a health of the transducer; or (ii) a downhole condition. The sensors downhole may include any suitable sensor or device, including, but not limited to, sensors for providing a measurement relating to: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; (xii) asphaltene; (xiii) corrosion; (xiv) water content; (xv) presence of gas; (xvi) water cut.
In another aspect, a method is disclosed that includes: placing a liquid-filled conduit in the wellbore; receiving from at least one sensor in the wellbore signals relating to a parameter of interest; transmitting pressure pulses in the liquid in the conduit at a downhole location that are representative of the signals received from the at least one sensor; and detecting the pressure pulses at an uphole location; processing the detected signals to estimate the parameter of interest; and recording the estimated parameter of interest in a suitable medium. The method may further include at last one repeater device at a downhole location that detects the pressure pulses, conditions the detected pressure pulses and transmits the conditioned pressure pulses through the liquid in the conduit. The parameter of interest may by any suitable parameter, including, but not limited to: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; (xii) asphaltene; (xiii) corrosion; (xiv) water content; and (xv) presence of gas.
In another aspect the method may include: placing a conduit in the well that contains a non-circulating liquid medium therein; and transmitting information in the form of pressure pulses through the medium, while the apparatus may include: a conduit in a well that contains a non-circulating liquid medium therein and a transmitter configured to transmit pressure pulses through the medium that are representative of signals to be transmitted between a downhole location and an uphole location of a well.
While the foregoing disclosure is directed to certain disclosed embodiments and methods, various modifications will be apparent to those skilled in the art. It is intended that all modifications that fall within the scopes of the claims relating to this disclosure be deemed as part of the foregoing disclosure. Also, an abstract is provided in this application with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

1. A system for communicating information between at least one location in a well and the surface, the system comprising:

a conduit having non-circulating liquid therein and extending from a first location in the wellbore to a second location;

a transducer that generates pressure pulses through the liquid in the conduit that are representative of data signals; and

a receiver spaced from the transducer that detects the pressure pulses and generates electrical signals representative of the detected pressure pulses.

2. The system of claim 1, wherein the transducer comprises a pulser that generates pressure pulses in the liquid in the conduit.

3. The system of claim 2, wherein the pulser is selected from a group consisting of: (i) a piezoelectric device that generates acoustic signals to generate the pressure pulses; (ii) a poppet-type pulser; and (iii) a disc-pulser.

4. The system of claim 1 further comprising at least one repeater that detects the pressure pulses generated by the transducer and retransmits the detected pulses through the liquid medium in the conduit.

5. The system of claim 1, wherein the transducer generates pressure pulses in the well and wherein the system further comprises a surface transducer that generates pressure pulses through the liquid in the conduit.

6. The system claim 1, wherein the transducer is an autonomous device that comprises:

a receiver that receives signals from at least one sensor;

a processor that converts the signals received from the at least one sensor into coded signals; and

a pulser that generates pressure pulses in the liquid representative of the coded signals.

7. The system of claim 1, wherein the transducer receives signals from at least one of: (i) a pressure sensor; (ii) a temperature sensor; (iii) an acoustic sensor; (iv) a flow rate measuring device; (v) a water-cut measurement device; (vi) a resistivity measuring device; (vii) a chemical detection sensor; (viii) a fiber optic sensor; (ix) a piezoelectric sensor; (x) a density sensor; (xi) a downhole controller; and (xii) a surface controller.

8. The system of claim 1, wherein the detector is uphole of the transducer, which location is selected from a group consisting of: (i) a location at the surface of the earth; (ii) a location in the wellbore uphole of the first transducer: (iii) a location at the sea bed; (iv) a location on a land rig; and (v) a location on an offshore platform.

9. The system of claim 7, wherein the transducer receives the signals via one of: (i) an electrical wire; (ii) an optical fiber; and (iii) wirelessly.

10. The system of claim 1 further comprising a power source that provides electrical power to the transducer, which power source is selected from a group consisting of: (i) a battery; (ii) a power generation unit that generates electrical power in the wellbore; and (iii) a power unit at the surface that supplies electrical power via an electrical conductor disposed in or along the conduit.

11. The system of claim 1, wherein the conduit is placed as one of: (i) inside a production tubing carrying fluid to thee surface; (ii) between a production tubing and a casing; and (iii) between a casing and formation surrounding the wellbore.

12. The system of claim 1 further comprising a plurality of sensors distributed in the well, and wherein the system further comprises: at least one secondary transducer in the wellbore that receives signals from an associated sensor in the plurality of sensors and transmits coded signals as pressure pulses through the liquid in the conduit that are representative of the received signals.

13. The system of claim 11, wherein the conduit is sealed at one of: (i) downhole end; and (ii) both ends.

14. The system of claim 12 wherein the secondary transducer comprises a transmitter that transmits coded signals in a form that is different from the transducer.

15. The system of claim 1 further comprising a second liquid-filled conduit and wherein a second transducer sends coded signals through the liquid in the second conduit.

16. The system of claim 1, wherein the generated pressure pulses are representative of a parameter of interest that is selected from a group consisting of: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; (xii) asphaltene; (xiii) corrosion; (xiv) water content; and (xv) presence of gas; (xvi) water-cut; (xvii) resistivity; and (xviii) an acoustic measurement.

17. A method for communicating information between a downhole location in a well and an uphole location, the method comprising:

placing a conduit in the wellbore, which conduit contains non-circulating liquid therein;

transmitting pressure pulses in the liquid in the conduit at first location that are representative of a selected signals;

detecting the pressure pulses at a second location and generating signals corresponding to a selected parameter;

processing the to obtain the selected signals; and

recording the selected signals in a suitable medium.

18. The method of claim 17 further comprising detecting the pressure pulses at a third location that is between the first and second locations and retransmitting the detected pressure pulses at the third location.

19. The method of claim 17, wherein the selected parameter is selected from a group consisting of: (i) pressure; (ii) temperature; (iii) resistivity; (iv) fluid flow rate; (v) capacitance; (v) viscosity; (vi) density; (vii) presence of a chemical in the wellbore; (viii) paraffin; (ix) scale; (x) hydrate; (xi) hydrogen sulfide; (xii) asphaltene; (xiii) corrosion; (xiv) water content; and (xv) presence of gas.

20. The method of claim 17, wherein the conduit is placed in the well in a manner that is one of: (i) inside a casing in the wellbore; (ii) between a casing in the wellbore and the formation surrounding the wellbore; (iii) inside a production tubing that carries the wellbore fluid.

21. A method for communicating in a well, comprising:

placing a conduit in the well that contains a non-circulating liquid medium therein; and

transmitting information in the form of pressure pulses through the liquid medium.

22. An apparatus, comprising:

a conduit configured to be deployed in a well, which conduit is closed at one end and contains therein liquid; and

a transmitter configured to transmit information in the form of pressure pulses through the liquid at a selected location in the conduit.