DOWNHOLE WIRELESS TWO-WAY TELEMETRY SYSTEM

Abstract: A petroleum well having a wireless power and data communication system is provided. The well uses the tubing and/or casing to communicate with and power a plurality of devices, such as sensors and controllable valves. An electrically isolating portion of a tubing hanger at the surface of the well and a ferromagnetic choke downhole may electrically isolate the tubing from the casing and provide a communications path. A plurality of modems positioned downhole along the tubing string communicate sensor information to a modem and a computer located at the surface of the well. Based on an analysis of the sensor information received by the computer, instructions can be communicated along the tubing string to the controllable valves to adjust the flow rate of lift gas passing through the valves.

Description: DOWNHOLE WIRELESS TWO-WAY TELEMETRY SYSTEM BACKGROUND OF THE INVENTION 1. Field of the Invention The present invention relates generally to a communication system for a petroleum or gas well having downhole devices for monitoring and adjusting production of the well, and in particular, to a communication system having a two-way telemetry backbone with redundant repeaters, sensors, and controllable valves. 2. Description of Related Art Gas-lift wells have been in use since the 1800 's and have proven particularly useful in increasing efficient rates of oil production where the reservoir natural lift is insufficient (see Brown, Connolizo and Robertson, West Texas Oil Lifting Short Course and H.W. Winkler, Misunderstood or Overlooked Gas-lift Design and Equipment Considera tions, SPE, p. 351 (1994)). Typically, in a gas- lift oil well, natural gas produced in the oil field is compressed and injected in an annular space between the casing and tubing and is directed from the casing into the tubing to provide a "lift" to the tubing fluid column for production of oil out of the tubing. Although the tubing can be used for the injection of the lift-gas and the annular space used to produce the oil, this is rare in practice. Initially, the gas-lift wells simply injected the gas at the bottom of the tubing, but with deep wells this requires excessively high kick off pressures. Later methods were devised to inject the gas into the tubing at various depths in the wells to avoid some of the problems associated with high kick off pressures (see U.S. Patent No. 5,267,469). The most common type of gas-lift well uses mechanical, bellows-type gas-lift valves attached to the tubing to regulate the flow of gas from the annular space into the tubing string (see U.S. Patent Nos . 5,782,261 and 5,425,425). In a typical bellows-type gas-lift valve, the bellows is preset or pre-charged to a certain pressure such that the valve permits communication of gas out of the annular space and into the tubing at the pre- charged pressure. The pressure charge of each valve is selected by a well engineer depending upon the position of the valve in the well, the pressure head, the physical conditions of the well downhole, and a variety of other factors, some of which are assumed or unknown, or will change over the production life of the well. Several problems are common with bellows-type gas- lift valves. First, the bellows often loses its pre- charge, causing the valve to fail in the closed position or changing its operating setpoint to other than the design goal. At other times exposure to overpressure may cause the valve to close and become inoperable. Another common failure is erosion around the valve seat and deterioration of the ball stem in the valve. This often leads to partial failure or at least inefficient production. Because the gas flow through a gas-lift valve is often not continuous at a steady state, but rather exhibits a certain amount of hammer and chatter as the valve rapidly opens and closes, valve degradation is common, leading to valve leakage. Failure or inefficient operation of bellows-type valves leads to corresponding inefficiencies in operation of a typical gas-lift well. In fact, it is estimated that well production is at least 5-15% less than optimum because of valve failure or operational inefficiencies. These cannot be corrected since the valve preset pressure is determined at design time, and there is insufficient real-time knowledge of a well's operating state to monitor, prevent or control instabilities in the lift process. Side-pocket mandrels coupled to the tubing string are known for receiving wireline insertable and retrievable gas-lift valves. Many gas-lift wells have gas-lift valves incorporated as an integral part of the tubing string, typically mounted to a pipe section. However, wireline replaceable side pocket mandrel type of gas-lift valves, such as those manufactured by Cameo or Weatherford, have many advantages and are quite common (see U.S. Patent Nos. 5,782,261 and 5,797,453). Gas-lift valves placed in a side pocket mandrel can be inserted and removed using a wireline and kickover tool either in top or bottom entry. In lateral and horizontal boreholes, coil tubing is used for insertion and removal of the gas-lift valves. It is common practice in oilfield production to shut off production of the well every three to five years and use a wireline to replace gas-lift valves. However, an operator often does not have a good estimate of which valves in the well have failed or degraded and need to be replaced. It would, therefore, be a significant advantage if a system and method were devised which overcame the inefficiency of conventional bellows-type gas-lift valves. Several methods have been devised to place controllable valves downhole on the tubing string but all such known devices typically use an electrical cable disposed along the tubing string to power and communicate with the gas-lift valves. It is, of course, highly undesirable and in practice difficult to use a cable along the tubing string either integral with the tubing string or spaced in the annulus between the tubing string and the casing because of the number of failure mechanisms present in such a system. The use of a cable presents difficulties for well operators while assembling and inserting the tubing string into a borehole. Additionally, the cable is subjected to corrosion and heavy wear due to movement of the tubing string within the borehole. An example of a downhole communication system using a cable is shown in PCT/EP97/01621. U.S. Patent No. 4,839,644 describes a method and system for wireless two-way communications in a cased borehole having a tubing string. However, this system describes a communication scheme for coupling electro- magnetic energy in a transverse electric mode (TEM) using the annulus between the casing and the tubing. It requires a toroidal antenna to launch or receive signals in a TEM mode, the Patent suggests the need for an insulated well head, and does not speak to the power source for a downhole module. The inductive coupling requires a substantially nonconductive fluid such as crude oil in the annulus between the casing and the tubing, and this oil must be of a higher density than the brine so that brine leakage does not gather at the bottom of the annulus. The invention described in U.S. Patent No. 4,839,644 has not been widely adopted as a practical scheme for downhole communication because it is expensive, has problems with brine leakage into the casing, and is difficult to use. Another system for downhole communication using mud pulse telemetry is described in U.S. Patent Nos. 4,648,471 and 5,887,657. Although mud pulse telemetry can be successful at low data rates, it is of limited usefulness where high data rates are required or where it is undesirable to have complex, mud pulse telemetry equipment downhole. Other methods of communicating within a borehole are described in U.S. Patent Nos. 4,468,665; 4,578,675; 4,739,325; 5,130,706; 5,467,083; 5,493,288; 5,574,374; 5,576,703; and 5,883,516. PCT Application W093/26115 describes a communication system for use on undersea pipelines which suffers from the need to provide a number of power sources on the pipeline. ,. It would, therefore, be a significant advance in the operation of gas-lift wells if an alternative to the conventional bellows type valve were provided, in particular, if the tubing string and the casing could be used as the communication and power conductors to control and operate a controllable gas-lift valve. All references cited herein are incorporated by reference to the maximum extent allowable by law. To the extent a reference may not be fully incorporated herein, it is incorporated by reference for background purposes and indicative of the knowledge of one of ordinary skill in the art. SUMMARY OF THE INVENTION The problems outlined above are largely solved by the petroleum well in accordance with the present invention. The petroleum well includes a wellbore extending in the earth and electrically conductive piping structure disposed in the wellbore, characterized by one or more devices electrically coupled to the piping structure in the wellbore for wireless reception of a time-varying electrical signal applied to the piping structure to power a device. At least one device is operable for sensing or controlling a physical characteristic in or proximate the wellbore. In an important application, the petroleum well is a controllable gas-lift well which includes a piping structure of a cased wellbore having a tubing string positioned and longitudinally extending within the casing. The position of the tubing string within the casing creates an annulus between the tubing string and the casing. A communication system, or telemetry backbone is provided for supplying power and communication signals downhole. The power is preferably a low voltage, AC current at conventional power frequencies in the range 50 to 400 Hertz, but in certain embodiments DC power may be used. ,. In a preferred embodiment of the present invention, a lower induction choke of ferromagnetic material is disposed on the tubing string downhole to act as a series impedance to current flow on the tubing. A hanger for hanging the tubing string within the well bore includes an insulated portion that electrically isolates the upper portion of the tubing string near the surface of the well. Communication preferably takes place on an electrically isolated section of the tubing string between the insulated portion of the hanger and the lower ferromagnetic choke. Power and communication signals are imparted to the electrically isolated portion of the tubing string and the casing acts as an electrical return. A plurality of downhole devices are connected to the tubing string downhole for monitoring and controlling the operation of the well. These downhole devices could include controllable gas-lift valves, sensors, electronics modules, and modems. A controllable gas-lift valve is coupled to the tubing to control gas injection between the interior and exterior of the tubing, more specifically, between the annulus and the interior of the tubing. The controllable gas-lift valve is powered and controlled from the surface to regulate the fluid communication between the annulus and the interior of the tubing. Sensors are located downhole to monitor the downhole physical conditions of the well . An electronics module is a control unit that receives signals from the sensors for communicating the signals to the surface and receives communication signals from the surface for controlling the controllable gas-lift valve. Modems are used for communicating signals between other downhole devices and the surface. In more detail, a surface computer having a modem imparts a communication signal to the tubing, and the signal is received by a modem downhole. The downhole modem, which is often a component of the electronics module, then relays the signal to the controllable gas- lift valve. Similarly, the downhole modem can receive and then communicate sensor information to the surface computer. Depending on the communication range that the modems are capable of providing under specific well conditions, the signals travelling along the tubing string may be relayed between downhole modems. Power is input into the tubing string and received downhole to control the operation of the controllable gas-lift valve. Preferably, a surface computer is coupled via the surface modem and the tubing to the downhole modems . The surface computer can receive measurements from a variety of sources, such as downhole or surface sensors, measurements of the oil output, and measurements of the compressed gas input to the well (flow and pressure) . Using such measurements, the computer can compute an optimum position of the controllable gas-lift valve, more particularly, the optimum amount of the gas injected from the annulus inside the casing through the controllable valve into the tubing. Additional enhancements are possible, such as controlling the amount of compressed gas input into the well at the surface, controlling back pressure on the wells, controlling a porous frit or surfactant injection system to foam the oil, and receiving production and operation measurements from a variety of other wells in the same field to optimize the production of the field. The ability to actively monitor current conditions downhole, coupled with the ability to control surface and downhole conditions, has many advantages in a gas-lift well. Gas-lift wells have four broad regimes of fluid flow, for example bubbly, Taylor, slug and annular flow. The downhole sensors of the present invention enable the detection and identification of the flow regime. The above referenced control mechanisms - surface computer, controllable valves, gas input, surfactant injection, etc. - provide the ability to attain and maintain optimum flow. In general, well tests and diagnoses may be performed and analyzed continuously and in real time. BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a schematic front view of a controllable gas-lift well according to one embodiment of the present invention, the gas-lift well having a tubing string and a casing positioned within a borehole. Figure 2A is an enlarged cut-away vertical portion of a tubing string in a cased borehole having an induction choke about the tubing. Figure 2B is an enlarged cut-away horizontal portion of the tubing string of Figure 2A. Figures 3A and 3B are cross-sectional front views of a controllable valve in a cage configuration according to one embodiment of the present invention. Figure 4 is an enlarged schematic front view of the tubing string and casing of Figure 1, the tubing string having an electronics module, sensors, and a controllable gas-lift valve operatively connected to an exterior of the tubing string. Figure 5 is a schematic of an equivalent circuit diagram for the controllable gas-lift well of Figure 1, the gas-lift well having an AC power source, the electronics module of Figure 3A, and the electronics module of Figure 4. Figure 6 is a system block diagram of an electronics module . DETAILED DESCRIPTION OF THE INVENTION As used in the present application, a "piping structure" can be one single pipe, a- tubing string, a well casing, a pumping rod, a series of interconnected pipes, rods, rails, trusses, lattices, supports, a branch or lateral extension of a well, a network of interconnected pipes, or other structures known to one of ordinary skill in the art. The preferred embodiment makes use of the invention in the context of an oil well where the piping structure comprises tubular, metallic, electrically-conductive pipe or tubing strings, but the invention is not so limited. For the present invention, at least a portion of the piping structure needs to be electrically conductive, such electrically conductive portion may be the entire piping structure (e.g., steel pipes, copper pipes) or a longitudinal extending electrically conductive portion combined with a longitudinally extending non-conductive portion. In other words, an electrically conductive piping structure is one that provides an electrical conducting path from a first location where a power source is electrically connected to a second location where a device and/or electrical return is electrically connected. The piping structure will typically be conventional round metal tubing, but the cross-section geometry of the piping structure, or any portion thereof, can vary in shape (e.g., round, rectangular, square, oval) and size (e.g., length, diameter, wall thickness) along any portion of the piping structure. Hence, a piping structure must have an electrically conductive portion extending from a first location of the piping structure to a second location of the piping structure. A "valve" is any device that functions to regulate the flow of a fluid. Examples of valves include, but are not limited to, bellows-type gas-lift valves and controllable gas-lift valves, each of which may be used to regulate the flow of lift gas into a tubing string of a r -well. The internal workings of valves can vary greatly, and in the present application, it is not intended to limit the valves described to any particular configuration, so long as the valve functions to regulate flow. Some of the various types of flow regulating mechanisms include, but are not limited to, ball valve configurations, needle valve configurations, gate valve configurations, and cage valve configurations. The methods of installation for valves discussed in the present application can vary widely. Valves can be mounted downhole in a well in many different ways, some of which include tubing conveyed mounting configurations, side-pocket mandrel configurations, or permanent mounting configurations such as mounting the valve in an enlarged tubing pod. The term "modem" is used generically herein to refer to any communications device for transmitting and/or receiving electrical communication signals via an electrical conductor (e.g., metal) . Hence, the term is not limited to the acronym for a modulator (device that converts a voice or data signal into a form that can be transmitted) /demodulator (a device that recovers an original signal after it has modulated a high frequency carrier) . Also, the term "modem" as used herein is not limited to conventional computer modems that convert digital signals to analog signals and vice versa (e.g., to send digital data signals over the analog Public Switched Telephone Network) . For example, if a sensor outputs measurements in an analog format, then such measurements may only need modulate a carrier signal and be transmitted—hence no analog-to-digital conversion is needed. As another example, a relay modem or communication device may only need to identify, filter, amplify, and/or retransmit a signal received. However, the modems used in this invention will generally be digital broadband, since these are widely available from commercial sources, and have the broadest applicability. The term "wireless" as used in the present invention means the absence of a conventional, insulated wire conductor e.g. extending from a downhole device to the surface. Using the tubing and/or casing as a conductor is considered "wireless." The term "sensor" as used in the present application refers to any device that detects, determines, monitors, records, or otherwise senses the absolute value of or a change in a physical quantity. Sensors as described in the present application can be used to measure temperature, pressure (both absolute and differential) , flow rate, seismic data, acoustic data, pH level, salinity levels, valve positions, or almost any other physical data. The term "electronics module" in the present application refers to a control device. Electronics modules can exist in many configurations and can be mounted downhole in many different ways. In one mounting configuration, the electronics module is actually located within a valve and provides control for the operation of a motor within the valve. Electronics modules can also be mounted external to any particular valve. Some electronics modules will be mounted within side pocket mandrels or enlarged tubing pockets, while others may be permanently attached to the tubing string. Electronics modules often are electrically connected to sensors and assist in relaying sensor information to the surface of the well. It is conceivable that the sensors associated with a particular electronics module may even be packaged within the electronics module. Finally, the electronics module is often closely associated with, and may actually contain, a modem for receiving, sending, and relaying communications from and to the surface of the well. S gnals that are received from the surface by the electronics module are often used to effect changes within downhole controllable devices, such as valves. Signals sent or relayed to the surface by the electronics module generally contain information about downhole physical conditions supplied by the sensors . The terms "up", "down", "above", "below" as used in this invention are relative terms to indicate position and direction of movement, and describe position "along hole depth" as is conventional in the industry. In highly deviated or horizontal wells, these terms may or may not correspond to absolute relative placement relative to the earth's surface. Referring to FIG. 1 in the drawings, a petroleum well according to the present invention is illustrated. The petroleum well is a gas-lift well 10 having a borehole 11 extending from a surface 12 into a production zone 14 that is located downhole. A production platform 20 is located at surface 12 and includes a hanger 22 for supporting a casing 24 and a tubing string 26. Casing 24 is of the type conventionally employed in the oil and gas industry. The casing 24 is typically installed in sections and is cemented in borehole 11 during well completion. Tubing string 26, also referred to as production tubing, is generally a conventional string comprising a plurality of elongated tubular pipe sections joined by threaded couplings at each end of the pipe sections, but may alternatively be continuously inserted, as coiled tubing for example. Production platform 20 also includes a gas input throttle 30 to control the input of compressed gas into an annular space 31 between casing 24 and tubing string 26. Conversely, output valve 32 permits the expulsion of oil and gas bubbles from an interior of tubing string 26 during oil production. , Gas-lift well 10 includes a communication system 34 for providing power and two-way communication downhole in well 10. Communication system 34 includes a lower ferromagnetic choke 42 that is installed on tubing string 26 to act as a series impedance to electric current flow. The size and material of ferromagnetic chokes 42 can be altered to vary the series impedance value. Hanger 22 includes an insulated portion 40 that electrically insulates tubing string 26 from casing 24 and from the remainder of the tubing string located above surface 12. The section of tubing string 26 between insulated portion 40 and lower choke 42 may be viewed as a power and communications path (see also FIG. 5) . Lower choke 42 is manufactured of high permeability magnetic material and is mounted concentric and external to tubing string 26. Choke 42 is typically insulated with shrink- wrap plastic film and may be hardened with epoxy to withstand rough handling. A computer and power source 44 having power and communication feeds 46 is disposed outside of borehole 11 at surface 12. Communication feeds 46 pass through a pressure feed 47 located in hanger 22 and are electrically coupled to tubing string 26 below insulated portion 40 of hanger 22. Power and communications signals are supplied to tubing string 26 from computer and power source 44. Referring to FIGS. 2A and 2B in the drawings, choke 42 comprises a toroid concentric with the tubing string 26 and within the annular space 31 between tubing string 26 and well casing 24. Choke 42 functions by creating a back-e.m.f. in tubing string 26 that opposes the e.m.f. from power source 44. The back-e.m.f is created by the magnetic flux changes in the choke, and by Faraday's Law of Induction this e.m.f. is proportional to the value of the magnetic flux and by its rate of change with time. When the pipe sections above the insulated portion 40 and below the lower choke 42 are grounded, the back-e.m.f. induced by lower choke 42 acts to oppose transmission of power and communications in a time- varying current through the choke 42. This effectively forms an isolated tubing section between insulated portion 40 and lower chokes 42. When the choke design creates a significant degree of isolation, the back- e.m.f. is close to the value of the imposed e.m.f. To the degree that the back-e.m.f. is less than the imposed e.m.f., the difference of the two allows a leakage current to flow through the choke section of the tubing. This power is lost, but is essential to the operation of the choke, because it is the magnetic flux from this leakage current passing through the choke that creates the back-e.m.f. in the choke section. Thus, the design goal is to create an induction choke that generates a back-e.m.f. as efficiently as possible from the leakage current . FIGS. 2A and 2B show a basic choke design and indicate the variables used in the design analysis. The defining variables and a self-consistent set of physical units are: L = length of choke, meters; a = choke inner radius, meters; b = choke outer radius, meters; r = distance from choke axis, meters; I = r.m.s. leakage current through choked pipe section, Amperes; ω = angular frequency of leakage current, radians per second; and μ = absolute magnetic permeability of choke material at radius r, Henries per meter. By definition, ω = 2πf, where f = frequency in Hertz. At a distance r from the leakage current (I), the r. .s. free space magnetic field (H) , in Amperes per meter, is given by: H = I/2πr. The magnetic field (H) is circularly symmetric about the choke axis, and can be visualized as magnetic lines of force forming circles around that axis. For a point within the choke material, the r.m.s. magnetic field (B) , in Teslas (Webers per square meter) , is given by: B = μH = μl/2πr. The r.m.s. magnetic flux (F) contained within the choke body, in Webers, is given by: F = J B dS where S is the cross-sectional area of the choke in square meters as shown in FIG. 3A, and the integration is over the area S. Performing the integration from the inner radius of the choke (a) , to the outer radius of the choke (b) , over the length of the choke (L) , provides: F = μLI ln(b/a) /2π where In is the natural logarithm function. The back-e.m.f. voltage generated by the magnetic flux (F) , in Volts, is given by: V = coF = 2πf F = μLIf ln(b/a) . Note that the back-e.m.f. (V) is directly proportional to the length (L) of the choke for constant values of a and b, the ferrite element internal and external radii. Thus by altering the length of the choke (L) , any desired back-e.m.f. (V) can be generated for a given leakage current (I) . Power can be transmitted at a certain frequency range within a functional bandwidth, and the communications can be transmitted at another frequency range within the same functional bandwidth. Because the frequency of the AC power is generally lower than that of the communications bandwidth provided, the AC power frequency will often determine the lower bound of the frequency range over which electrical isolation is required. Because the electrical impedance of a choke rises linearly with frequency, if the choke provides adequate impedance at the AC power frequency, typically it will also be adequate at the higher frequencies used for communication. However, ferromagnetic materials are characterized by a maximum operating frequency above which ferromagnetic properties are not exhibited. Thus the upper frequency bound of the ferromagnetic material chosen for the choke construction must be adequate to provide isolation at the upper bound of the communication band. The method of electrically isolating a section of the tubing string as shown in FIG.l is not the sole method of providing power and communications signals downhole. Instead of using a hanger 22 with an insulated portion 40, an upper ferromagnetic choke (not shown) could be disposed around tubing string 26. Similarly, an electrically insulating connector could be used downhole in place of lower ferromagnetic choke 42. In the preferred embodiment shown in FIG. 1, power and communication signals are supplied on tubing string 26, with the electrical return being provided by casing 24. Instead, the electrical return could be provided by an earthen ground. An electrical connection to earthen ground could be provided by passing a wire through casing 24 or by connecting the wire to the tubing string below lower choke 42 (if the lower portion of the tubing string was grounded) . An alternative power and communications path could be provided by the casing 24. In a configuration similar to that used with tubing string 26, a portion of casing 24 could be electrically isolated to provide a telemetry backbone for transmitting power and communication signals dqwnhole. If ferromagnetic chokes were used to isolate a portion of the casing, the chokes would be disposed concentrically around the outside of the casing. Instead of using chokes with the casing 24, electrically isolating connectors could be used similar to isolated portion 40 of hanger 22. In embodiments using casing 24 to supply power and communications signals downhole, an electrical return could be provided either via the tubing string 26 or via an earthen ground. A packer 48 is placed within casing 24 downhole below lower choke 42. Packer 48 is located above production zone 14 and provides hydraulic isolation between production zone 14 and the well space above it. The packer electrically connects metal tubing string 26 to metal casing 24. Typically, the electrical connections between tubing string 26 and casing 24 would not allow electrical signals to be transmitted or received up and down borehole 11 using tubing string 26 as one conductor and casing 24 as another conductor. However, the disposition of insulated portion 40 and lower ferromagnetic choke 42 create an electrically isolated section of the tubing string 26, which provides a system and method to provide power and communication signals up and down borehole 11 of gas-lift well 10. Referring still to FIG. 1 in the drawings, a plurality of downhole devices 50 is electrically coupled to tubing string 26 between insulated portion 40 and lower ferromagnetic choke 42. Some of the downhole devices 50 comprise controllable gas-lift valves. Other downhole devices 50 may comprise electronics modules, sensors, communication devices (typically broadband digital modems), or conventional valves. Although power and communication transmission take place on the electrically isolated portion of the tubing string, downhole devices 50 may be mechanically coupled above or below lower choke 42. Referring to FIGS. 3A and 3B in the drawings, the installation of one of the downhole devices (analogous to downhole devices 50 in FIG. 1) is illustrated in more detail. As mentioned previously, conventional bellows- type gas-lift valves are often used in gas-lift wells to admit pressurized gas from annular space 31 to the inside of tubing string 26. In the present invention, any or all of the conventional valves can be replaced with controllable gas-lift valves. In FIGS. 3A and 3B, a controllable valve 220 according to the present invention is illustrated. Controllable valve 220 includes a housing 222 and is slidably received in a side pocket mandrel 224. Side pocket mandrel 224 includes a housing 226 having a gas inlet port 228 and a gas outlet port 230. When controllable valve 220 is in an open position, gas inlet port 228 and gas outlet port 230 provide fluid communication between annular space 31 and ■ an interior of tubing string 26. In a closed position, controllable valve 220 prevents fluid communication between annular space 31 and the interior of tubing string 26. In a plurality of intermediate positions located between the open and closed positions, controllable valve 220 meters the amount of gas flowing from annular space 31 into tubing string 26 through gas inlet port 228 and gas outlet port 230. A stepper motor 234 is disposed within housing 222 of controllable valve 220 for rotating a pinion 236. Pinion 236 engages a worm gear 238, which in turn raises and lowers a cage 240. When valve 220 is in the closed position, cage 240 engages a seat 242 to prevent flow into an orifice 244, thereby preventing flow through valve 220. This "cage" valve configuration is believed to be a preferable design from a fluid mechanics view when compared to the alternative embodiment of a needle valve cςnfiguration. More specifically, fluid flow from inlet port 228, past the cage and seat juncture (240, 242) permits precise fluid regulation without undue fluid wear on the mechanical interfaces . It should be apparent to one skilled in the art that needle valve designs or other valve designs could be employed. Controllable valve 220 includes a check valve head 250 disposed within housing 222 below cage 240. An inlet 252 and an outlet 254 cooperate with gas inlet port 228 and gas outlet port 230 when valve 220 is in the open position to provide fluid communication between annulus 31 and the interior of tubing string 26. Check valve head 250 insures that fluid flow only occurs when the pressure of fluid in annulus 31 is greater than the pressure of fluid in the interior of tubing string 26. An electronics module 256 is disposed within the housing of controllable valve 220. Electronics module 256 is operatively connected to valve 220 for communication between the surface of the well and the valve. The electronics module 256 contains a spread spectrum communication device for receiving power and communicating on tubing string 26 as previously described. In addition to sending signals to the surface to communicate downhole physical conditions, the electronics module can receive instructions from the surface and adjust the operational characteristics of the valve 220. Valve 220 is physically located below lower choke 42 but is electrically coupled to tubing string 26 above the choke 42 by a jumper wire 64. A ground wire 66 is electrically connected between valve 220 and a bow spring centralizer 60 in order to provide an electrical return for valve 220. Bow spring centralizer 60 is used to center tubing string 26 relative to casing 24. When located in the electrically isolated portion of the tubing string 26, each bow spring centralizer 60 includes PVC insulators 62 to electrically isolate casing 24 from tubing string 26. Referring to FIG. 4 in the drawings, an alternative installation of several downhole devices (analogous to downhole devices 50 in FIG. 1) is illustrated. Tubing string 26 includes an annularly enlarged pocket, or pod 100 formed on the exterior of tubing string 26. Enlarged pocket 100 includes a housing that surrounds and protects a controllable gas-lift valve 99 (schematically illustrated) and an electronics module 106. In this mounting configuration, gas-lift valve 99 and electronics module 106 are rigidly mounted to tubing string 26 and are not insertable and retrievable by wireline. Alternatively, valve 99 and electronics module 106 may by disposed in a side-pocket mandrel (not shown) so that the devices can be easily inserted and removed by wireline. A ground wire 102 (similar to ground wire 66 of FIG. 3B) is fed through enlarged pocket 100 to connect electronics module 106 to bow spring centralizer 60, which is grounded to casing 24. Electronics module 106 is external to valve 99 and is rigidly connected to tubing string 26 for receiving communications and power via a power and signal jumper 104. Controllable valve 99 includes a motorized cage valve head 108 and a check valve head 110 that are schematically illustrated in FIG. 4. Cage valve head 108 and check valve head 110 operate in a similar fashion to cage 240 and check valve head 250 of FIG. 3A. The valve heads 108, 110 cooperate to control fluid communication between annular space 31 and the interior of tubing string 26. A plurality of sensors are used in conjunction with electronics module 106 to control the operation of controllable valve 99 and gas-lift well 10. Pressure sensors, such as those produced by Three Measurements Specialties, Inc., can be used to measure internal tubing pressure, internal pod housing pressures, and differential pressures across gas-lift valves. In commercial operation, the internal pod pressure is considered unnecessary. A pressure sensor 112 is rigidly mounted to tubing string 26 to sense the internal tubing pressure of fluid within tubing string 26. A pressure sensor 118 is mounted within pocket 100 to determine the differential pressure across cage valve head 108. Both pressure sensor 112 and pressure sensor 118 are independently electrically coupled to electronics module 106 for receiving power and for relaying communications. Pressure sensors 112, 118 are podded to withstand the severe vibration associated with gas-lift tubing strings . Temperature sensors, such as those manufactured by Four Analog Devices, Inc. (e.g. LM-34) are used to measure the temperature of fluid within the tubing, housing pod, power transformer, or power supply. A temperature sensor 114 is mounted to tubing string 26 to sense the internal temperature of fluid within tubing string 26. Temperature sensor 114 is electrically coupled to electronics module 106 which receives power and relays communications . The temperature transducers used downhole are rated for -50 to 300 °F and are conditioned by input circuitry to +5 to +255 °F. The raw voltage developed at a power supply in electronics module 106 is divided in a resistive divider element so that 25.5 volts will produce an input to the analog/digital converter of 5 volts. A salinity sensor 116 is also electrically connected to electronics module 106. Salinity sensor 116 is rigidly and sealingly connected to the housing of enlarged pocket 100 to sense the salinity of the fluid in annulus 31. It should be understood that the alternate embodiments illustrated in FIGS. 3B and 4 could include or exclude any number of the sensors 112, 114, 116 or 118. Sensors other than those displayed could also be employed in either of the embodiments. These could include gauge pressure sensors, absolute pressure sensors, differential pressure sensors, flow rate sensors, tubing acoustic wave sensors, valve position sensors, or a variety of other analog signal sensors. Similarly, it should be noted that while electronics module 256 shown in FIG. 3B is packaged within valve 220, an electronics module similar to electronics module 106 could be packaged with various sensors and deployed independently of controllable valve 220. Referring now to FIG. 5 in the drawings, an equivalent circuit diagram for gas-lift well 10 is illustrated and should be compared to FIG. 1. Computer and power source 44 includes an AC power source 120 and a modem 122 electrically connected between casing 24 and tubing string 26. As discussed previously, electronics module 256 is mounted internally within a valve housing that is wireline insertable and retrievable downhole. Electronics module 106 is independently and permanently mounted in an enlarged pocket on tubing string 26. For purposes of the equivalent circuit diagram of FIG. 5, it is important to note that electronics modules 256, 106 appear identical, both modules 256, 106 being electrically connected between casing 24 and tubing string 26. Electronics modules 256, 106 may contain or omit different components and combinations such as sensors 112, 114, 116, 118. Additionally, the electronics modules may or may not be an integral part of a controllable valve. Each electronics module includes a power transformer 124 and a data transformer 128. Data transformer 128 is electrically coupled to modem 130. Computer and power source 44 also includes a surface controller (not shown in FIG. 5) , which is electrically coupled via a surface communication device (e.g., modem 122) and the tubing string 26 and/or casing 24 to a downhole communication device (e.g., modem 130). Each modem 130 may communicate with modem 122 either directly, or by relay through intermediate communication devices (comprising e.g., modems, filters, data transformers, amplifiers) to relay a signal as required to effect changes in the operation of the well. For example, a surface computer can receive measurements from a variety of sources, such as the downhole sensors, measurements of the oil output, and measurements of the compressed gas input to the well (flow and pressure) . Using such measurements, the computer can compute an optimum position of a controllable gas valve, more particularly, the optimum amount of the gas injected from annular space 31 through each controllable valve into tubing string 26. Additional parameters may be controlled by the computer, such as controlling the amount of compressed gas input into the well at the surface, controlling back pressure on the wells, controlling a porous frit or surfactant injection system to foam the oil, and receiving production and operation measurements from a variety of other wells in the same field to optimize the production of the field or production zone. Depending on the communication range that the modems 130 are capable of providing under specific well conditions, the transmission of sensor and control data up and down the well may require that these signals be relayed between modems 130 rather than passed directly from the surface to the selected downhole devices 50 (see Figure 1) . This relay method can be applied to both conventional and multilateral well completions. , Preferably the downhole modems 130 are placed so that each can communicate with the next two modems up the well and the next two modems down the well. This redundancy allows communications to remain operational even in the event of the failure of one of the downhole modems 130. The ensemble of downhole devices 50 having modems 130 can provide a permanent telemetry backbone that can be part of the infrastructure of the well. Such a telemetry backbone may provide a means to measure the conditions in each part of the well and transmit the data to a surface computer or a downhole controller, and for the computer to transmit control signals to open or close downhole valves to set back pressure, set gas injection rate, adjust flow rates, and so on. This level of control allows production from the well to be optimized against criteria that may be dynamically managed in substantially real-time, rather than being fixed by a static production goal. For instance, the optimum under one set of economic conditions may be maximum recovery from the reservoir, but under different economic conditions it may be beneficial to alter the production method to minimize the cost of recovery by using lift gas to maximum effect. Referring to FIG. 6 in the drawings, electronics module 106 is illustrated in more detail. Although the components of any particular electronics module may vary, the components shown in FIG. 6 could be present in electronics modules packaged inside the housing of a valve (such as electronics module 256) or electronics modules that are external to a valve. Amplifiers and signal conditioners 180 are provided for receiving inputs from a variety of sensors such as tubing temperature, annulus temperature, tubing pressure, annulus pressure, lift gas flow rate, valve position, salinity, differential pressure, acoustic readings, and others. Some of these sensors are analogous to sensors 112, 114, 116, and 118 shown in FIG. 4. Preferably, any low noise operational amplifiers are configured with non-inverting single ended inputs (e.g. Linear Technology LT1369) . All amplifiers 180 are programmed with gain elements designed to convert the operating range of an individual sensor input to a meaningful 8 bit output. For example, one psi of pressure input would produce one bit of digital output, 100 degrees of temperature will produce 100 bits of digital output, and 12.3 volts of raw DC voltage input will produce an output of 123 bits. Amplifiers 180 are capable of rail-to-rail operation. Electronics module 106 is electrically connected to modem 122 via casing 24 and tubing string 26. Address switches 182 are provided to address a particular device from modem 122. As shown in FIG. 6, 4 bits of addresses are switch selectable to form the upper 4 bits of a full 8 bit address. The lower 4 bits are implied and are used to address the individual elements within each electronics module 106. Thus, using the configuration illustrated, sixteen modules are assigned to a single modem 122 on a single communications line. As configured, up to four modems 122 can be accommodated on a single communications line. Electronics module 106 also includes a programmable interface controller (PIC) 170, which preferably has a basic clock speed of 20 MHz and is configured with 8 analog-to-digital inputs 184 and 4 address inputs 186. PIC 170 includes a transistor-transistor level (TTL) serial communications, universal asynchronous receiver- transmitter UART 188, as well as a motor controller interface 190. PIC 170 is electrically coupled to a modem 171 (analogous to modem 130 of FIG. 5) that communicates with modem 122. Electronics module 106 also contains a power supply 166. A nominal 6 volts AC line power is supplied tg power supply 166 along tubing string 26. Power supply 166 converts this power to plus 5 volts DC at terminal 192, minus 5 volts DC at terminal 194, and plus 6 volts DC at terminal 196. A ground terminal 198 is also shown. The converted power is used by various elements within electronics module 106. Although connections between power supply 166 and the components of electronics module 106 are not shown, the power supply 166 is electrically coupled to the following components to provide the specified power. PIC 170 uses plus 5 volts DC, while modem 171 uses plus 5 and minus 5 volts DC. A motor 199 (analogous to stepper motor 234 of FIG. 3A) is supplied with plus 6 volts DC from terminal 196. Power supply 166 comprises a step-up transformer for converting the nominal 6 volts AC to 7.5 volts AC. The 7.5 volts AC is then rectified in a full wave bridge to produce 9.7 volts of unregulated DC current. Three-terminal regulators provide the regulated outputs at terminals 192, 194, and 196 which are heavily filtered and protected by reverse EMF circuitry. Modem 171 is the major power consumer in electronics module 165, typically using 350+ milliamps at plus/minus 5 volts DC when transmitting. Modem 171 is a digital broad-band modem having an IC/SS power line carrier chip set such as models EG ICS1001, ICS1002 and ICS1003 manufactured by National Semiconductor. Modem 171 is capable of 300-3200 baud data rates at carrier frequencies ranging from 14 kHz to 76 kHz. U.S. Patent No. 5,488,593 describes the chip set in more detail and is incorporated herein by reference. There exist alternative implementations of suitable modems based on various transmission principles, both broadband and narrow-band, which are commercially available and which would be suited to the purpose of providing bi-directional communications between modems . PIC 170 controls the operation of stepper motor 199 through a stepper motor controller 200 such as model SA1042 manufactured by Motorola. Controller 200 needs only directional information and simple clock pulses from PIC 170 to drive stepper motor 199. An initial setting of controller 200 conditions all elements for initial operation in known states. Stepper motor 199, preferably a MicroMo gear head, positions a cage valve head 201 (analogous to cage 240 of FIG. 3A) , which is the principal operative component of the controllable gas- lift valve. Stepper motor 199 provides 0.4 inch-ounce of torque and may be operated at up to 500 steps per second. A complete revolution of stepper motor 199 consists of 24 individual steps, and the gearhead provides a mechanical reduction of 989:1, providing a maximum speed of 1 revolution per minute at the gearhead output shaft at a torque of 24 inch-pounds, which is more than sufficient to seat and unseat valve 201. While this illustrative example of a suitable embodiment is based on the use of a stepper motor, it is important to note that there exist alternative methods for electronic control appropriate to other types of motors, many of which would be suitable for the purpose of controlling the degree of opening of valve 201. PIC 170 communicates through digital modem 171 to modem 122 via casing 24 and tubing string 26. PIC 170 uses a MODBUS 584/985 PLC communications protocol. The protocol is ASCII encoded for transmission. OPERATION A large percentage of the artificially lifted oil production today uses gas-lift to help bring the reservoir oil to the surface. In such gas-lift wells, compressed gas is injected downhole outside the tubing, usually in the annulus between the casing and the tubing, and mechanical gas-lift valves permit communication of t e gas into the tubing section, thus inducing the rise of the fluid column within the tubing to the surface. As previously described, conventional mechanical gas-lift valves are unreliable because of leakage and failures . Such leaks and failures are not readily detectable at the surface and probably reduce a well's production efficiency on the order of 15 percent through lower production rates and higher demands on the field lift gas compression systems. The wireless telemetry backbone of the present invention provides a system for monitoring and controlling the operation of a gas-lift well. By placing downhole devices, such as sensors, electronics modules, controllable gas-lift valves, and modems on the tubing string of the well, the well can be accurately monitored and changes can be made to promote efficient production. Each of the individual downhole devices is individually addressable via wireless communication through the tubing and casing. That is, a modem at the surface and an associated controller communicates to a number of downhole modems. When the surface modem is communicating with a particular downhole modem, other downhole modems can act as intermediates by relaying signals as needed. Sensors report such measurements as downhole tubing pressures, downhole casing pressures, downhole tubing and casing temperatures, lift gas flow rates, gas valve position, and acoustic data (see Fig. 4, sensors 112, 114, 116, and 118). The surface computer (either local at the wellhead or centrally located in a producing field) continuously combines and analyzes the downhole data as well as surface data, to compute a real-time tubing pressure profile. An optimal gas-lift flow rate for each controllable gas-lift valve is computed from this data. Alternatively, the sensors may report their measurements via repeater downhole modems to a controller associated with a gas-lift valve to similarly control the operation of the valve for optimal or desired flow rates. In addition to controlling the flow rate of the well, production may be controlled to produce an optimum fluid flow state. Unwanted conditions such as "heading" and "slug flow" can be avoided. As previously mentioned, it is possible to attain and maintain the optimum flow regime appropriate to the desired production rate of a well . By being able to determine unwanted flow conditions quickly downhole, production can be controlled to avoid such unwanted conditions. A fast detection by the surface computer of flow conditions allows the computer to correct any flow problems by adjusting such factors as the position of the controllable gas-lift valve, the gas injection rate, back pressure on tubing at the wellhead, and even injection of surfactant. Even though many of the examples discussed herein are applications of the present invention in petroleum wells, the present invention also can be applied to other types of wells, including but not limited to water wells and natural gas wells. One skilled in the art will see that the present invention can be applied in many areas where there is a need to provide a controllable valve within a borehole, well, or any other area that is difficult to access. Also, one skilled in the art will see that the present invention can be applied in many areas where there is an already existing conductive piping structure and a need to route power and communications to a controllable valve in a same or similar path as the piping structure. A water sprinkler system or network in a building for extinguishing fires is an example of a piping structure that may be already existing and may have a same or similar path as that desired for routing power and communications to a controllable valve. In such case another piping structure or another portion of the same piping structure may be used as the electrical return. The steel structure of a building may also be used as a piping structure and/or electrical return for transmitting power and communications to a valve in accordance with the present invention. The steel reinforcing bar in a concrete dam or a street pavement may be used as a piping structure and/or electrical return for transmitting power and communications to a controllable valve, or sensors which would otherwise be difficult to access, in accordance with the present invention. The transmission lines and network of piping between wells or across large stretches of land may be used as a piping structure and/or electrical return for transmitting power and communications to a controllable valve in accordance with the present invention. Surface refinery production pipe networks may be used as a piping structure and/or electrical return for transmitting power and communications to a controllable valve in accordance with the present invention. Thus, there are numerous applications of the present invention in many different areas or fields of use. It should be apparent from the foregoing that an invention having significant advantages has been provided. While the invention is shown in only a few of its forms, it is not just limited but is susceptible to various changes and modifications without departing from the spirit thereof.

Claims: C L A I M S 1. A petroleum well having a wellbore extending in the earth and electrically conductive piping structure disposed in the wellbore, characterized by one or more devices electrically coupled to the piping structure in the wellbore for wireless reception of a time-varying electrical signal applied to the piping structure wherein at least one device is powered by the signal for sensing or controlling a physical characteristic in or proximate the wellbore. 2. The petroleum well in accordance with claim 1, including a communication signal applied to the piping structure for communicating with a device. 3. The petroleum well in accordance with claim 1, wherein a device is operable to apply a time-varying electrical signal to the piping structure to transmit information . 4. The petroleum well in accordance with claim 1, wherein the device is a sensor for sensing a physical characteristic in the wellbore such as temperature, pressure, or acoustic. 5. The petroleum well in accordance with claim 1, wherein the device is a valve which operates when commanded by a wireless signal applied to the piping structure . 6. The petroleum well in accordance with claim 1, wherein the petroleum well is a gas lift well, the piping structure includes tubing and one device is a gas lift valve coupled to the tubing and adjustable to regulate the fluid flow between the interior and exterior of the tubing. 7. The petroleum well in accordance with claim 1, including an induction choke located proximate a portion of the piping structure to route the time varying signal within the piping structure. 8. The petroleum well in accordance with claim 1, including a plurality of devices each adapted to send and receive communication signals for communicating with other devices in different regions of the well. 9. The petroleum well in accordance with claim 1, including a controller and some of the devices being sensors and at least one device being a valve, whereby the operation of the valve is determined by the controller based on input from the sensors. 10. In a petroleum well having a wellbore extending in the earth and electrically conductive piping structure disposed in the wellbore, a method of operating the wellbore characterized by applying a time varying electrical signal to the piping structure which is received by one or more wireless devices electrically coupled to the piping structure in the wellbore to effect the operation of at least one device in the earth. 11. The method of claim 10, a device comprising a sensor, the method including sensing a physical characteristic such as temperature, pressure, or acoustic, and communicating such physical characteristic along the piping structure. 12. The method of claim 10, wherein a time varying power signal and a time varying communication signal is applied to the piping structure to power and communicate with a number of devices. 13. The method of claim 10, wherein the petroleum well is gas-lift and at least one device is a controllable valve, including communicating with the valve and regulating the fluid flow through the valve. 14. The method of claim 13, including controlling the operation of the gas-lift well. 15. The method of claim 14, wherein the operation includes the unloading, kickoff, or production of the well .

Inventors: BURNETT ROBERT REX, CARL FREDERICK GORDON JR, SAVAGE WILLIAM MOUNTJOY, VINEGAR HAROLD J, BURNETT, ROBERT, REX, CARL, FREDERICK, GORDON, JR., SAVAGE, WILLIAM, MOUNTJOY, VINEGAR, HAROLD, J.
Applicants: SHELL CANADA LTD, SHELL INT RESEARCH, SHELL CANADA LIMITED, SHELL INTERNATIONALE RESEARCH MAATSCHAPPIJ B.V.
Application year: 2001
Main classification: E21B47
IPC codes: E21B17, E21B34, E21B43, E21B47, H04B5