Patent Abstract:
A gas-lift well having a controllable gas-lift valve is provided. The well uses the tubing and casing to communicate with and power the controllable valve from the surface. Induction chokes at the surface and downhole electrically isolate the tubing from the casing. A high band-width, adaptable communication system is used to communicate between the controllable valve and the surface. Additional sensors, such as pressure, temperature, and acoustic sensors, may be provided downhole to more accurately assess downhole conditions. The controllable valve is varied opened or closed, depending on downhole conditions, oil production, gas usage and availability, to optimize production and assist in unloading. While conventional, bellows-type, gas-lift valves frequently fail and leak—often undetected—the controllable valve hereof permits known precise operation and concomitant control of the gas-lift well.

Full Description:
CROSS-REFERENCES TO RELATED APPLICATIONS 
     This application claims the benefit of the U.S. Provisional Applications in the following table, all of which are hereby incorporated by reference: 
     
       
         
               
             
               
               
               
               
             
           
               
                   
               
               
                 U.S. PROVISIONAL APPLICATIONS 
               
             
          
           
               
                   
                 Serial 
                   
                   
               
               
                 T&amp;K # 
                 Number 
                 Title 
                 Filing Date 
               
               
                   
               
               
                 TN 1599 
                 60/177,999 
                 Toroidal Choke Inductor for 
                 Jan. 24, 2000 
               
               
                   
                   
                 Wireless Communication and 
               
               
                   
                   
                 Control 
               
               
                 TH 1599x 
                 60/186,376 
                 Toroidal Choke Inductor for 
                 Mar. 2, 2000 
               
               
                   
                   
                 Wireless Communication and 
               
               
                   
                   
                 Control 
               
               
                 TH 1600 
                 60/178,000 
                 Ferromagnetic Choke in 
                 Jan. 24, 2000 
               
               
                   
                   
                 Wellhead 
               
               
                 TH 1600x 
                 60/186,380 
                 Ferromagnetic Choke in 
                 Mar. 2, 2000 
               
               
                   
                   
                 Wellhead 
               
               
                 TH 1601 
                 60/186,505 
                 Reservoir Production 
                 Mar. 2, 2000 
               
               
                   
                   
                 Control from Intelligent 
               
               
                   
                   
                 Well Data 
               
               
                 TH 1602 
                 60/178,001 
                 Controllable Gas-Lift Well 
                 Jan. 24, 2000 
               
               
                   
                   
                 and Valve 
               
               
                 TH-1603 
                 60/177,883 
                 Permanent, Downhole, 
                 Jan. 24, 2000 
               
               
                   
                   
                 Wireless, Two-Way 
               
               
                   
                   
                 Telemetry Backbone Using 
               
               
                   
                   
                 Redundant Repeater, Spread 
               
               
                   
                   
                 Spectrum Arrays 
               
               
                 TH 1668 
                 60/177,998 
                 Petroleum Well Having 
                 Jan. 24 2000 
               
               
                   
                   
                 Downhole Sensors, 
               
               
                   
                   
                 Communication, and Power 
               
               
                 TH 1669 
                 60/177,997 
                 System and Method for Fluid 
                 Jan. 24, 2000 
               
               
                   
                   
                 Flow Optimization 
               
               
                 TS6185 
                 60/181,322 
                 Optimal Predistortion in 
                 Feb. 9, 2000 
               
               
                   
                   
                 Downhole Communications 
               
               
                   
                   
                 System 
               
               
                 TH 1671 
                 60/186,504 
                 Tracer Injection in a 
                 Mar. 2, 2000 
               
               
                   
                   
                 Production Well 
               
               
                 TH 1672 
                 60/186,379 
                 Oilwell Casing Electrical 
                 Mar. 2, 2000 
               
               
                   
                   
                 Power Pick-Off Points 
               
               
                 TH 1673 
                 60/186,394 
                 Controllable Production 
                 Mar. 2, 2000 
               
               
                   
                   
                 Well Packer 
               
               
                 TH 1674 
                 60/186,382 
                 Use of Downhole High 
                 Mar. 2, 2000 
               
               
                   
                   
                 Pressure Gas in a Gas Lift 
               
               
                   
                   
                 Well 
               
               
                 TH 1675 
                 60/186,503 
                 Wireless Smart Well Casing 
                 Mar. 2, 2000 
               
               
                 TH 1677 
                 60/186,527 
                 Method for Downhole Power 
                 Mar. 2, 2000 
               
               
                   
                   
                 Management Using 
               
               
                   
                   
                 Energization from 
               
               
                   
                   
                 Distributed Batteries or 
               
               
                   
                   
                 Capacitors with 
               
               
                   
                   
                 Reconfigurable Discharge 
               
               
                 TH 1679 
                 60/186,393 
                 Wireless Downhole Well 
                 Mar. 2, 2000 
               
               
                   
                   
                 Interval Inflow and 
               
               
                   
                   
                 Injection Control 
               
               
                 TH 1681 
                 60/186,394 
                 Focused Through-Casing 
                 Mar. 2, 2000 
               
               
                   
                   
                 Resistivity Measurement 
               
               
                 TH 1704 
                 60/186,531 
                 Downhole Rotary Hydraulic 
                 Mar. 2, 2000 
               
               
                   
                   
                 Pressure for Valve 
               
               
                   
                   
                 Actuation 
               
               
                 TH 1705 
                 60/186,377 
                 Wireless Downhole 
                 Mar. 2, 2000 
               
               
                   
                   
                 Measurement and Control For 
               
               
                   
                   
                 Optimizing Gas Lift Well 
               
               
                   
                   
                 and Field Performance 
               
               
                 TH 1722 
                 60/186,381 
                 Controlled Downhole 
                 Mar. 2, 2000 
               
               
                   
                   
                 Chemical Injection 
               
               
                 TH 1723 
                 60/186,378 
                 Wireless Power and 
                 Mar. 2, 2000 
               
               
                   
                   
                 Communications Cross-Bar 
               
               
                   
                   
                 Switch 
               
               
                   
               
             
          
         
       
     
     The current application shares some specification and figures with the following commonly owned and concurrently filed applications in the following table, all of which are hereby incorporated by reference: 
     
       
         
               
             
               
               
               
               
             
           
               
                   
               
               
                 COMMONLY OWNED AND CONCURRENTLY 
               
               
                 FILED U.S. PATENT APPLICATIONS 
               
             
          
           
               
                   
                 Serial 
                   
                   
               
               
                 T&amp;K # 
                 Number 
                 Title 
                 Filing Date 
               
               
                   
               
               
                 TH 1599ff 
                 09/769,047 
                 Choke Inductor for Wireless 
                 Jan. 24, 2001 
               
               
                   
                   
                 Communications and Control 
               
               
                 TH 1600ff 
                 09/769,048 
                 Induction Choke for Power 
                 Jan. 24, 2001 
               
               
                   
                   
                 Distribution in Piping 
               
               
                   
                   
                 Structure 
               
               
                 TH 1603ff 
                 09/768,655 
                 Permanent Downhole, 
                 Jan. 24, 2001 
               
               
                   
                   
                 Wireless, Two-Way 
               
               
                   
                   
                 Telemetry Backbone Using 
               
               
                   
                   
                 Redundant Repeater 
               
               
                 TH 1668ff 
                 09/769,046 
                 Petroleum Well Having 
                 Jan. 24, 2001 
               
               
                   
                   
                 Downhole Sensors, 
               
               
                   
                   
                 Communication, and Power 
               
               
                 TH 1669ff 
                 09/768,656 
                 System and Method for Fluid 
                 Jan. 24, 2001 
               
               
                   
                   
                 Flow Optimization 
               
               
                   
               
             
          
         
       
     
    
    
     BACKGROUND OF THE INVENTION 
     1. Field of the Invention 
     The present invention relates generally to a gas-lift well having a controllable gas-lift valve, and in particular, to a controllable gas-lift valve which communicates with the surface and is powered using the tubing string and casing as the conductor. 
     2. Description of Related Art 
     Gas-lift wells have been in use since the 1800&#39;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 Considerations , 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. Pat. 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. Pat. 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. 
     Referring to FIG. 1 in the drawings, a typical bellows-type gas-lift valve  310  has a pre-charge cylinder  312 , a metal bellows  314 , and entry ports  316  for communicating gas from the annular space outside the tubing string. Gas-lift valve  310  also includes a ball  318  that sealingly engages a valve seat  319  when valve  310  is in a closed position. When gas-lift valve  310  is in an open position, ball  318  no longer engages valve seat  319 , thereby allowing gas from the annular space to pass through entry port  316 , past ball  318 , and through exit port  320 . 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 setpoint to operate at other than the design goal, and exposure to overpressure causes similar problems. Another common failure is erosion around valve seat  319  and deterioration of the ball stem in the valve. This leads to partial failure of the valve 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 ball  318  rapidly opens and closes, ball and valve seat degradation are 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. Fundamentally these difficulties are caused by the present inability to monitor, control, or prevent instabilities, since the valve characteristics are set at design time, and even without failure they cannot be easily changed after the valve is installed in the well. 
     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 have many advantages and are quite commonly used (see U.S. Pat. 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 workover tool either in top or bottom entry. In lateral and horizontal boreholes, coiled 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 periodically 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 or hydraulic line 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. Pat. 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 electromagnetic energy in a transverse electric mode (TEM) using the annulus between the casing and the tubing. The system requires a toroidal antenna to launch or receive in a TEM mode, and the patent suggests an insulated wellhead. The inductive coupling of the system 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 that brine so that leaked brine does not gather at the bottom of the annulus. This system does not speak to the issue of providing power to the downhole module. The invention described in U.S. Pat. No. 4,839,644 has not been widely adopted as a practical scheme for downhole two-way 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. Pat. 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. Pat. 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. 
     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 electrically controllable gas-lift well in accordance with the present invention. Broadly speaking, the controllable gas-lift well includes 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 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. Communication signals and power are sent from the surface using the tubing and casing as conductors. The power is preferably a low voltage AC at conventional power frequencies in the range 50 to 400 Hertz, but in certain embodiments DC power may also be used. 
     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 connected to the controllable gas-lift valve. Similarly, the modem downhole can communicate sensor information to the surface computer. Further, power is input into the tubing string and received downhole to control the operation of the controllable gas-lift valve. Preferably, the casing is used as the ground return conductor. Alternatively, a distant ground may be used as the electrical return. In a preferred embodiment, the controllable gas-lift valve includes a motor which operates to insert and withdraw a cage trim valve from a seat, regulating the gas injection between the annulus and the interior of the tubing, or other means for controlling gas flow rate. 
     In enhanced forms, the controllable gas-lift well includes one or more sensors downhole which are preferably in contact with the downhole modem and communicate with the surface computer, although downhole processing may also be used to minimize required communications data rate, or even to make the downhole system autonomous. Such sensors as temperature, pressure, hydrophone, microphone, geophone, valve position, flow rates, and differential pressure gauges are advantageously used in many situations. The sensors supply measurements to the modem for transmission to the surface or directly to a programmable interface controller operating the controllable gas-lift valve for controlling the fluid flow through the gas-lift valve. 
     Preferably, ferromagnetic chokes are coupled to the tubing to act as a series impedance to current flow on the tubing. In a preferred form, an upper ferromagnetic choke is placed around the tubing below the tubing hanger, and the current and communication signals are imparted to the tubing below the upper ferromagnetic choke. A lower ferromagnetic choke is placed downhole around the tubing with the controllable gas-lift valve electrically coupled to the tubing above the lower ferromagnetic choke, although the controllable gas-lift valve may be mechanically coupled to the tubing below the lower ferromagnetic choke. It is desirable to mechanically place the operating controllable gas-lift valve below the lower ferromagnetic choke so that the borehole fluid level is below the choke. 
     Preferably, a surface controller (computer) is coupled via a surface master modem and the tubing to the downhole slave modem of the controllable gas-lift valve. The surface computer can receive measurements from a variety of sources, such as downhole and 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 of flow regime. The above referenced control mechanisms-surface computer, controllable valves, gas input, surfactant injection, etc.—provide the ability to attain and maintain the desired flow regime. In general, well tests and diagnostics can be performed and analyzed continuously and in near real time. 
     In one embodiment, all of the gas-lift valves in the well are of the controllable type in accordance with the present invention. It is desirable to lift the oil column from a point in the borehole as close as possible to the production packer. That is, the lowest gas-lift valve is the primary valve in production. The upper gas-lift valves are used for annular unloading of the well during production initiation. In conventional gas-lift wells, these upper valves have bellows pre-set with a margin of error to ensure the valves close after unloading. This means operating pressures that permit closing of unloading valves as each successive valve is uncovered. These margins result in the inability to use the full available pressure to lift at maximum depth during production: lift pressure is lost downhole to accommodate the design margin offset at each valve. Further, such conventional valves often leak and fail to fully close. Use of the controllable valves of the present invention overcomes such shortcomings. 
     In an alternate embodiment, a number of conventional mechanical bellows-type gas-lift valves are longitudinally spaced on the tubing string in a conventional manner. The lower-most valve is preferably a bellows-type valve which aids in unloading of the well in the normal manner. The bellows-type valve&#39;s pre-charged pressure is set normally. That is, the unloading pushes annular fluid into the tubing through successively deeper gas-lift valves until the next to the last gas-lift valve is cleared by the fluid column. Production is then maintained by gas injection through a controllable gas-lift valve located on the tubing string, which as outlined above receives power and communication signals through its connection to the tubing and a grounding centralizer. While only one controllable gas-lift valve is described, more can be used if desired, depending upon the characteristics of a particular well. If the controllable gas-lift valve fails, the production is diverted through the lowest manual valve above the controllable gas-lift valve. 
     Construction of such a controllable gas-lift well is designed to be as similar to conventional construction methodology as possible. That is, after casing the well, a packer is typically set above the production zone. The tubing string is then fed through the casing into communication with the production zone. As the tubing string is made up at the surface, a lower ferromagnetic choke is placed around one of the conventional tubing string sections for positioning above the bottom valve, or a pre-assembled joint prepared with the valve, electronics module, and choke may be be used. In the sections of the tubing string where it is desired, a gas-lift valve is coupled to the string. In a preferred form the downhole valve is tubing conveyed, but a side pocket mandrel for receiving a slickline insertable and retrievable gas-lift valve may also be used. With the side-pocket mandrel, either a controllable gas-lift valve in accordance with the present invention can be inserted, or a conventional bellows-type valve can be used. The tubing string is made up to the surface, where a ferromagnetic choke or other electrical isolation device such as an electrically insulating joint is again placed around the tubing string below the tubing hanger. Communication and power leads are then connected through the wellhead feed through to the tubing string below the upper ferromagnetic choke or other isolation device. 
     In an alternative form of the controllable gas lift well, a pod having only a sensor and communication device is inserted without the necessity of including a controllable gas-lift valve in every pod. That is, an electronics module having pressure, temperature or acoustic sensors or other sensors, a power supply, and a modem may be tubing conveyed or inserted into a side pocket mandrel for communication to the surface computer or with other downhole modules and controllable gas lift valves using the tubing and casing as conductors. Alternatively, such electronics modules may be mounted directly on the tubing (tubing conveyed) and not be configured to be wireline replaceable. If directly mounted to the tubing an electronic module or a controllable gas-lift valve may only be replaced by pulling the entire tubing string. In an alternative form, the controllable valve can have its separate control, power and wireless communication electronics mounted in the side pocket mandrel of the tubing and not in the wireline replaceable valve. In the preferred form, the electronics are integral and replaceable along with the gas-lift valve. In another form, the high permeability magnetic chokes may be replaced by electrically insulated tubing sections. Further, an insulated tubing hanger in the wellhead may replace the upper choke or such upper insulating tubing sections. 
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS 
     FIG. 1 is a cross-sectional front view of a prior art, bellows-type gas-lift valve. 
     FIG. 2 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. 
     FIG. 3 is a schematic front view of the tubing string and casing of FIG. 2, the tubing string having side pocket mandrels positioned thereon. 
     FIG. 4A is an enlarged schematic front view of the side pocket mandrel of FIG. 3 and a controllable gas-lift valve, the valve having an internal electronics module and being wireline retrievable from the side pocket mandrel. 
     FIG. 4B is a cross-sectional side view of the controllable gas-lift valve of FIG. 4A taken at IV—IV. 
     FIGS. 5A-5C are cross-sectional front views of a controllable valve in a cage configuration according to one embodiment of the present invention. 
     FIG. 6 is an enlarged schematic front view of the tubing string and casing of FIG. 2, the tubing string having an electronics module, sensors, and a controllable gas-lift valve operatively connected to an exterior of the tubing string. 
     FIG. 7 is an enlarged schematic front view of the tubing string and casing of FIG. 2, the tubing string having a controllable gas-lift valve permanently connected to the tubing string. 
     FIG. 8 is a cross sectional side views of the controllable gas-lift valve of FIG. 7 taken at VIII—VIII. 
     FIG. 9 is a schematic of an equivalent circuit diagram for the controllable gas-lift well of FIG. 2, the gas-lift well having an AC power source, the electronics module of FIG. 4, and the electronics module of FIG.  6 . 
     FIG. 10 is a schematic diagram depicting a surface computer electrically coupled to an electronics module of the gas-lift well of FIG.  2 . 
     FIG. 11 is a system block diagram of the electronics module of FIG.  10 . 
     FIG. 12 illustrates a disposition of chokes and controllable gas-lift valves to provide control of the valves when the tubing-casing annulus is partially filled with conductive fluid. and 
     FIG. 13 depicts a time-series chart showing the relationships between degree of opening of a gas-lift valve, annulus pressure, tubing pressure, and lifted fluid flow regimes. 
    
    
     DETAILED DESCRIPTION OF THE INVENTION 
     As used in the present application, 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 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 to modulate a carrier to be transmitted-hence no analog-to-digital conversion is needed. As another example, a relay/slave modem or communication device may only need to identify, filter, amplify, and/or retransmit a signal received. 
     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. Signals 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 “first end” and “second end” as used herein are defined generally to call out a side or portion of a piping structure, which may or may not encompass the most proximate locations, as well as intermediate locations along a called out side or portion of the piping structure. Similarly, in accordance with conventional terminology of oilfield practice, the descriptors “upper”, “lower”, “uphole” and “downhole” refer to distance along hole depth from the surface, which in deviated wells may or may not accord with absolute vertical placement measured with reference to the ground surface. 
     Referring to FIG. 2 in the drawings, a petroleum well according to the present invention is illustrated. The petroleum well is a gas-lift well  210  having a borehole  211  extending from a surface  212  into a production zone  214  that is located downhole. A production platform is located at surface  212  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 the borehole 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. The production platform 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 the interior of tubing string  26  during oil production. 
     An upper ferromagnetic choke  40  or insulating pipe joint, and a lower ferromagnetic choke  42  are installed on tubing string  26  to act as a series impedance to electric current flow. The size and material of ferromagnetic chokes  40 ,  42  can be altered to vary the series impedance value. The section of tubing string  26  between upper choke  40  and lower choke  42  may be viewed as a power and communications path (see also FIG.  9 ). Both upper and lower chokes  40 ,  42  are manufactured of high permeability magnetic material and are mounted concentric and external to tubing string  26 . Chokes  40 ,  42  are typically insulated with shrink wrap plastic and encased with fiber-reinforced epoxy to withstand rough handling. 
     A computer and power source  44  having power and communication feeds  46  is disposed outside of borehole  211  at surface  212 . Communication feeds  46  pass through a pressure feed  47  located in hanger  22  and are electrically coupled to tubing string  26  below upper choke  40 . Power and communications signals are supplied to tubing string  26  from computer and power source  44 . 
     A packer  48  is placed within casing  24  downhole below lower choke  42 . Packer  48  is located above production zone  214  and serves to isolate production zone  214  and to electrically connect metal tubing string  26  to metal casing  24 . Similarly, above surface  212 , the metal hanger  22  (along with the surface valves, platform, and other production equipment) 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  211  using tubing string  26  as one conductor and casing  24  as another conductor. However, the disposition of upper and lower ferromagnetic chokes  40 ,  42  around tubing string  26  alter the electrical characteristics of tubing  26 , providing a system and method to provide power and communication signals up and down borehole  211  of gas-lift well  210 . 
     A plurality of conventional bellows-type gas-lift valves  50  are operatively connected to tubing string  26  (see discussion of FIG. 1 in the Background of the Invention). The number of conventional valves  50  disposed along tubing string  26  depends upon the depth of the well and the well lift characteristics. A controllable gas-lift valve  52  in accordance with the present invention is attached to tubing string  26  as the penultimate gas-lift valve. In this embodiment, only one controllable gas-lift valve  52  is used. 
     Referring now to FIG. 3 in the drawings, the downhole configuration of bellows-type valve  50  and controllable valve  52 , as well as the electrical connections with casing  24  and tubing string  26 , is depicted. The pipe sections of tubing string  26  are conventional and where it is desired to incorporate a gas-lift valve in a particular pipe section, a side pocket mandrel  54 , commonly available in the industry, is employed. Each side pocket mandrel  54  is a non-concentric enlargement of tubing string  26  that permits wireline retrieval and insertion of either bellows-type valves  50  or controllable valves  52  downhole. 
     Referring still to FIG. 3, but also to FIGS. 4A and 4B, a plurality of bow spring centralizers  60  may be installed at various locations along the length of tubing string  26  to center tubing string  26  relative to casing  24 . When located between upper and lower chokes  40 ,  42 , each bow spring centralizer  60  includes insulators  62  to electrically isolate casing  24  from tubing string  26 . A power and signal jumper wire  64  electrically connects controllable valve  52  to tubing string  26  at a point between upper choke  40  and lower choke  42 . Although controllable valve  52  is shown below lower choke  42 , the valve  52  could be disposed above lower choke  42  such that controllable valve  52  is electrically coupled to tubing string  26  without using a power jumper. A ground wire  66  provides a return path from controllable valve  52  to casing  24  via electrically conductive centralizer  60 . While jumper wire  64  and ground wire  66  are illustrated schematically in FIGS. 3 and 4A, it will be appreciated that in commercial use jumper wire  64  and ground wire  66  may be insulated and predominantly integral to a housing of side pocket mandrel  54 . 
     It should be noted that the power supplied downhole through tubing string  26  is effective only when annulus  31  does not contain an electrically conductive liquid between upper choke  40  and lower choke  42 . If an electrically conductive liquid is present in the annulus  31  between the chokes  40 ,  42 , the liquid will cause a short circuit of the current in tubing string  26  to casing  24 . 
     Use of controllable valves  52  may be preferable to use of conventional bellows valves for several reasons. For example, conventional bellows valves  50  (see FIG. 1) often leak when they should be closed during production, resulting in inefficient well operation. Additionally, conventional bellows valves  50  are usually designed to use sequentially decremented operating presssures resulting in the inability to make use of full available lift pressure, therefore resulting in further inefficiency. 
     Referring more specifically to FIGS. 4A and 4B, a more detailed illustration of controllable gas-lift valve  52  and side pocket mandrel  54  is provided. Side pocket mandrel  54  includes a housing  68  having a gas inlet port  72  and a gas outlet port  74 . When controllable valve  52  is in an open position, gas inlet port  72  and gas outlet port  74  provide fluid communication between annular space  31  and an interior of tubing string  26 . In a closed position, controllable valve  52  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  52  meters the amount of gas flowing from annular space  31  into tubing string  26  through gas inlet port  72  and gas outlet port  74 . 
     Controllable gas-lift valve  52  includes a generally cylindrical, hollow housing  80  configured for reception in side pocket mandrel  54 , and is furnished with a latching method to leave and retrieve the valve using a tubing accessible method such as slickline. An electronics module  82  is disposed within housing  80  and is electrically connected to a stepper motor  34  for controlling the operation thereof. Operation of stepper motor  84  adjusts a needle valve head  86 , thereby controlling the position of needle valve head  86  in relation to a valve seat  88 . Movement of needle valve head  86  by stepper motor  84  directly affects the amount of fluid communication that occurs between annular space  31  and the interior of tubing string  26 . When needle valve head  86  fully engages valve seat  88  as shown in FIG. 4B, the controllable valve  52  is in the closed position. 
     Seals  90  are made of an elastomeric material and allow controllable valve  52  to sealingly engage side pocket mandrel  54 . Slip rings  92  surround a lower portion of housing  80  and are electrically connected to electronics module  82 . Slip rings  92  provide an electrical connection for power and communication between tubing string  26  and electronics module  82 . 
     Controllable valve  52  includes a check valve head  94  disposed within housing  80  below needle valve head  86 . An inlet  96  and an outlet  98  cooperate with inlet port  72  and outlet port  74  when valve  52  is in the open position to provide fluid communication between annulus  31  and the interior of tubing string  26 . Check valve  94  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 . 
     Referring to FIGS. 5A,  5 B, and  5 C in the drawings, another embodiment of 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  (similar to side pocket mandrel  54  of FIG.  4 A). 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 motor  234  is disposed within housing  222  of controllable valve  220  for rotating shaft  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 . As shown in more detail in FIG. 5B, a shoulder  246  on seat  242  is configured to sealingly engage a mating collar on cage  240  when the valve is closed. This “cage” valve configuration with symmetrically spaced and opposing flow ports is believed to be a preferable design since the impinging flow minimizes erosion when compared to the alternative embodiment of a needle valve configuration (see FIG.  4 B). 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. 
     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 is operatively connected to valve  220  for communication between the surface of the well and the valve. 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 . 
     While FIGS. 4A,  4 B, and FIGS. 5A-5C illustrate the embodiments of the controllable valve in accordance with the present invention, other embodiments are possible without departing from the spirit and scope of the present invention. In particular, patent publication WO02/059457, entitled “Downhole Motorized Control Valve” describes yet another embodiment and is incorporated herein by reference. Referring to FIG. 6 in the drawings, an alternative installation configuration for a controllable valve assembly is shown and should be contrasted with the slide pocket mandrel configuration of FIG.  4 A. In FIG. 6, tubing  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 the controllable gas-lift valve assembly and an electronics module  106 . In this mounting configuration, gas-lift valve assembly is rigidly mounted to tubing string  26  and is not insertable and retrievable by wireline. A ground wire  102  (similar to ground wire  66  of FIG. 4A) 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 rigidly connected to tubing string  26  and receives communications and power via a power and signal jumper  104 . The electronics module  106  in this configuration is not insertable or retrievable by wireline. 
     Enlarge pocket  100  includes a housing that surrounds and protects controllable the gas-lift valve assembly and an electronics module  106 . In this mounting configuration, gas-lift valve assembly is rigidly mounted to tubing string  26  and is not insertable and retrievable by wireline. A ground wire  102  (similar to ground wire  66  of FIG. 4A) is fed through enlarged pocket  100  to connect electronics module  106  to bow spring centralizer  60 , which is grounded to causing  24 . Electronics module  106  is rigidly connected to tubing string  26  and receives communications and power via a power and signal jumper  104 . The electronics module  106  in this configuration is not insertable or retrievable by wireline. 
     Controllable valve assembly includes a motorized cage valve  108  and a check valve  110  that are schematically illustrated in FIG.  6 . Cage valve  108  and check valve  110  operate in a similar fashion to cage  240  and check valve head  250  of FIG.  5 A. The valves  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 and gas-lift well  210 . Pressure sensors, such as those produced by Three Measurement 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  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 potted 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  for receiving power and for relaying 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. 4A,  5 C and  6  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  82  shown in FIG. 4B is packaged within valve  52 , an electronics module similar to electronics module  106  could be packaged with various sensors and deployed independently of controllable valve  52 . 
     Referring to FIGS. 7 and 8 in the drawings, a controllable gas-lift valve  132  having a valve housing  133  is mounted on a tubing conveyed mandrel  134 . Controllable valve  132  is mounted similar to most of the bellows-type gas-lift valves that are in use today. These valves are not wireline replaceable, and must be replaced by pulling tubing string  26 . An electronics module  138  is mounted within housing  133  above a motor  142  that drives a needle valve head  144 . A check valve  146  is disposed within housing  133  below needle valve head  144 . Stepper motor  142 , needle valve head  144 , and check valve  146  are similar in operation and configuration to those used in controllable valve  52  depicted in FIG.  4 B. It should be understood, however, that valve  132  could include a cage configuration (as opposed to the needle valve configuration) similar to valve  220  of FIG.  5 A. In similar fashion to FIG. 4B, an inlet opening  148  and an outlet opening  150  are provided to provide a fluid communication path between annulus  31  and the interior of tubing string  26 . 
     Power and communications are supplied to electronics module  138  by a power and signal jumper  140  connected between electronics module  138  and housing  133 . Power is supplied to housing  133  either directly from tubing string  26  or via a wire (not shown) connected between housing  133  and tubing string  26 . A ground wire  136  couples electronics module  138  centralizer  60  for grounding purposes. 
     Although not specifically shown in the drawings, electronics module  138  could have any number of sensors electrically coupled to the module  138  for sensing downhole conditions. These could include pressure sensors, temperature sensors, salinity sensors, flow rate sensors, tubing acoustic wave sensors, valve position sensors, or a variety of other analog signal sensors. These sensors would likely be connected in a manner similar to that used for sensors  112 ,  114 ,  116 , and  118  of FIG.  6 . 
     Referring now to FIG. 9 in the drawings, an equivalent circuit diagram for gas-lift well  210  is illustrated and should be compared to FIG.  2 . Computer and power source  44  includes an AC power source  120  and a master modem  122  electrically connected between casing  24  and tubing string  26 . As discussed previously, electronics module  82  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 . Although not shown, the equivalent circuit diagram could also include depictions of electronics module  256  of FIG. 5A or electronic module  138  of FIG.  8 . 
     For purposes of the equivalent circuit diagram of FIG. 9, it is important to note that while electronics modules  82 ,  106  appear identical, both modules  82 ,  106  being electrically connected between casing  24  and tubing string  26 , electronics modules  82 ,  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 the controllable valve. Each electronics module includes a power transformer  124  and a data transformer  128 . Data transformer  128  is electrically coupled to a slave modem  130 . 
     Referring to FIG. 10 in the drawings, a block diagram of a communications system  152  according to the present invention is illustrated. FIG. 10 should be compared and contrasted with FIGS. 2 and 9. Communications system  152  includes master modem  122 , AC power source  120 , and a computer  154 . Computer  154  is coupled to master modem  122 , preferably via an RS  232  bus, and runs a multitasking operating system such as Windows NT and a variety of user applications. AC power source  120  includes a  120  volt AC input  156 , a ground  158 , and a neutral  160  as illustrated. Power source  120  also includes a fuse  162 , preferably 7.5 amp, and has a transformer output  164  at approximately 6 volts AC and 60 Hz. Power source  120  and master modem  122  are both connected to casing  24  and tubing  26 . 
     Communications system  152  includes an electronics module  165  that is analogous to module  82  in FIG. 4B, module  256  in FIG. 5B, module  106  in FIG. 6, and module  138  in FIG.  8 . Electronics module  165  includes a power supply  166  and an analog-to-digital conversion module  168 . A programmable interface controller (PIC)  170  is electrically coupled to a slave modem  171  (analogous to slave modem  130  of FIG.  9 ). Couplings  172  are provided for coupling electronics module  165  to casing  24  and tubing  26 . 
     Referring to FIG. 11 in the drawings, electronics module  165  is illustrated in more detail. 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.  6 . 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  165  is electrically connected to master modem  122  via casing  24  and tubing string  26 . Address switches  182  are provided to address a particular device from master modem  122 . As shown in FIG. 11, 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  165 . Thus, using the configuration illustrated, sixteen modules are assigned to a single master modem  122  on a single communications line. As configured, up to four master modems  122  can be accommodated on a single communications line. 
     Electronics module  165  also includes 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 TTL level serial communications UART  188 , as well as a motor controller interface  190 . 
     Electronics module  165  also contains a power supply  166 . A nominal 6 volts AC line power is supplied to 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  165 . 
     Although connections between power supply  166  and the components of electronics module  165  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 slave modem  171  uses plus 5 and minus 5 volts DC. A motor  199  (analogous to motor  84  of FIG. 4B, motor  234  of FIG. 5A, and motor  142  of FIG. 8) 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 typically a wideband digital modem having an IC/SS power line carrier chip set such as models EG ICS 1001, ICS 1002 and ICS 1003 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. Pat. No. 5,488,593 describes the chip set in more detail and is incorporated herein by reference. Any modem with an adequate data rate may be substituted for this choice of specific components. 
     PIC  170  controls the operation of a suitable valve control motor  199  through, for example, 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 rotating stem control valve  201  (analogous to needle valve heads  86 ,  108 , and  144  of FIGS. 4B,  6 , and  8 , respectively), which is the principal operative component of the controllable gas-lift valve. Alternatively, motor  199  could position a cage analogous to cage  240  of FIG.  5 A. Motor  199  provides 0.4 inch-ounce of torque and rotates at up to 500 steps per second. A complete revolution of stepper motor  199  consists of 24 individual steps. The output of stepper motor  199  is directly coupled to a 989:1 gear head, and the output shaft from the gearhead may thus rotate at a maximum of 1.26 revolutions per minute, and can exert a maximum torque of 24.7 inch-pounds. This produces the necessary torque to open and close needle valve  201 . The continuous rotational torque required to open and close needle valve  201  is 3 inch-pounds with 15 inch-pounds required to seat and unseat the valve  201 . 
     PIC  170  communicates through modem  171  to the surface modem  122  via casing  24  and tubing string  26 . PIC  170  uses a MODBUS 584/985 PLC communications protocol, with commands and data ASCII encoded for transmission. 
     As noted previously with reference to FIG. 2, the embodiments thus far described for providing power and communications for controllable gas lift valve  52  are restricted to the well condition where annular space between tubing  26  and casing  24  is cleared of conductive fluid. In some circumstances for example during the unloading or kickoff processes, it may desirable to allow all of the valves in a gas lift well to be powered and controlled from the surface. 
     FIG. 12 illustrates an embodiment in which power and communications may be established for valves when the annulus  31  is only partially cleared of conductive fluid. As in the previous embodiments, surface equipment  44  includes an AC power source and communications device coupled by conductors  46  to tubing  26  and casing  24 . An upper choke  40  impedes AC which would otherwise be electrically short-circuited through hanger  22 , and the AC is thus directed down tubing string  26  to downhole equipment. At each location where it is desired to place a downhole electronics module  50  there is a choke  41  which creates an impedance to AC and therefore generates a voltage on the tubing  34  between the tubing above and below the choke. This voltage is connected by wires  64  and  66  to each electronics module  50 , and thus the voltage developed by the action of each choke  41  may be used to transfer power and communications signals to its corresponding electronics module  50 . Connections  64 ,  66 , and the action of chokes  41 , also allow communications signals from each module  50  to be impressed on tubing  34  and received at surface equipment  44 . When the level of conducting fluid  182  is at level  1  of FIG. 12, none of the chokes will function to power their modules, since AC between tubing and casing is electrically short-circuited by fluid  182  before it reaches any of the chokes. However, when the fluid level is at level  2 , the upper choke  41  is effective since there is no longer an electrical short-circuit between tubing and casing above the upper choke  41 , and a potential difference can be developed on the tubing section that passes through the upper choke. Thus power and communications become available for the electronics module above level  2 . The same principle applies to the intermediate levels: as the surface of fluid  182  is driven downwards past levels  3 ,  4  and  5 , the corresponding electronics modules at these levels become operable. The lowermost module is energized by choke  42 , and becomes operable when the fluid  182  is as illustrated in FIG. 12, below the lowest choke  42 . 
     Operation 
     FIG. 13 demonstrates the benefit of the availability of data and a method to respond to observations with a downhole control action. The chart of FIG. 13 presents a time series trend of three values. The first value is valve position  401 , expressed as a percent of full open (full open=100%) which is quantified by referencing the Y-axis on the right side of the plot. The second value is annulus pressure  402 , which is quantified by referencing the Y-axis scale on the left side of the plot. The annulus pressure is the pressure of the lift gas being supplied to the well and is upstream of the downhole controllable gas lift valve. The third value is the tubing pressure  403 , which is quantified by referencing the Y-axis on the left side of the plot. The tubing pressure is the pressure in the production tubing downstream of the controllable gas lift valve. 
     In a typical oil well, reducing the pressure in the tubing by injecting bubbles of gas into the liquid column above the point of lift gas injection into the tubing results in a decreased back-pressure on the reservoir. The decrease in back-pressure results in increased differential pressure from the reservoir to the tubing and therefore flow from the reservoir to the tubing and to the surface. An increase in downhole tubing pressure creates an increased back pressure on the reservoir, which decreases flow, even to the point of stopping inflow from the reservoir completely. It is important that the tubing pressure remain low and stable in order to achieve stable production rates from the reservoir to the surface and to the production facilities. Unstable flow causes upset conditions in production facilities due to the large changes in flow rate over short periods of time. Large surges in liquid and gas production can upset production processes creating inefficient and possibly hazardous conditions. 
     As previously discussed, conventional gas lift valves are configured before installation using information available at the time of configuration. As the well conditions change over time, the original configuration of the gas lift valve may no longer be appropriate for the new conditions. The effect of this miss-match is shown in FIG.  13 . 
     A gas lift valve port that is inappropriately large has been created by fully opening the downhole controllable gas lift valve as shown at  404 . The reservoir fluids are allowed to fill the tubing, causing the pressure to increase at  405 . Gas is introduced into the annulus, causing the annulus pressure to increase at  406 . The gas does not flow from the annulus to the tubing as the annulus pressure is less than the tubing pressure. The downstream pressure must be less than the upstream pressure in order to initiate flow. Gas does not flow from the tubing back into the annulus due to the presence of a reverse-flow check valve which prevents such backflow. 
     When the annulus pressure  406  increases sufficiently to exceed the tubing pressure  405 , gas flow is initiated into the tubing, the tubing pressure is reduced as the gas reduces the density of the tubing fluids via injection of bubbles into the liquid column at  407 . As the tubing pressure drops, the annulus pressure also begins to decline at  408  as the gas is flowing from the annulus to the tubing at a rate higher than gas is being introduced into the annulus from the surface. The gas flow rate from the annulus to the tubing is a function of the downhole controllable gas lift valve opening position which is 100%, and the differential pressure between the annulus and the tubing. If the gas flow out of the annulus into the tubing exceeds the injection rate into the annulus at the surface, the annulus pressure falls. If the gas flow out of the annulus into the tubing is less than the injection rate into the annulus at the surface, the annulus pressure increases. 
     If annulus outflow exceeds inflow for an extended period of time, the pressure difference between the annulus and the tubing may decline to level where insufficient gas enters the tubing to keep the fluids aerated to the degree required to maintain a low tubing pressure as shown at  409 . At that point, the tubing pressure begins to increase,  410 , as the density increases. The annulus pressure increases,  411 , also as the differential pressure between the annulus and tubing is so small that the gas flow rate into the tubing from the annulus is less than the rate of gas input into the annulus at the surface. 
     At some point,  412 , the pressure differential between the annulus and the tubing increases sufficiently for the volume of gas entering the tubing to reduce the density and cause the pressure to decrease,  413 . This begins another “heading” cycle that originally began at  407 . Left unchecked, such cycles repeat continuously. The surges of liquids and gas delivered to the producing facilities and the surges of lift gas demanded from the supply system generally influence not only the well suffering from the cause, but also affect other wells in the system. It is therefore desirable to correct this problem as quickly as possible. Conventional gas lift installations require that the well be closed in (stopping production) and remedial service work be performed on the well to remove the improperly sized or eroded valve and replace with one that has been configured for the new producing conditions. This results in significant cost and deferment of oil production. 
     In the case of a downhole controllable gas lift valve, the flow capacity of the valve can be adjusted without any service work or loss of production by closing the valve to some degree, such as closing from 97% open to 52% open as shown at  414 . The result of this action is to present excessive flow out of the annulus into the tubing, which causes the upstream (annulus) pressure to stabilize,  415 , and also the downstream (tubing pressure) to stabilize,  416 . 
     With downhole data available in real-time, a further adjustment,  417 , of the downhole controllable gas lift valve maintains stable annulus pressure,  418 , and tubing pressure,  419 , but causes the tubing pressure to decline slightly from the previous pressure. This pressure decline slightly reduces the back pressure on the reservoir, slightly increasing production rate as a result. A conventional gas lift system cannot provide the data or the ability to make such small adjustments, which enable continuous optimization of the producing system via feedback and response loops. 
     To illustrate the benefit of independent control for every lift gas valve in a well, FIG. 12 may be used to describe a process for unloading a gas lift well based on the methods of the present invention. 
     Typically the unloading process starts with the annulus  31  filled with completion fluid  182 , to level  1  of the well as illustrated in FIG.  12 . The completion fluid  182  is normally a brine which is electrically conductive, and thus creates an electrical connection between tubing  34  and casing  24 . Each downhole module  50  controls a motorized gas lift valve which may be opened to permit fluid, either liquid or gas, to pass from the annulus  31  to the interior of tubing  34 . At the start of the unloading process all of these lift gas valves are open, but none of the modules  50  can be powered since the completion fluid creates an electrical short circuit between the tubing  26  and the casing  24  at a point above all of the chokes  41 ,  42 . 
     To initiate the unloading process, lift gas under pressure from a surface supply is admitted to the annulus  31 , and starts to displace the completion fluid through the open lift gas valves of each of the downhole modules  40 , thus driving down the level of the completion fluid. When the level of the completion fluid has reached level  2  indicated on FIG. 12, the first module  50  immediately above level  2  becomes powered and thus controllable, since the tubing and casing above level  2  are no longer electrically short-circuited above level  2 . The lift gas valve associated with the module immediately above level  2  may now be regulated to control the flow of lift gas into the tubing  34 . The rising column of lift gas bubbles lightens the liquid column between this first valve and the surface, inducing upwards flow in the production tubing. At this point in the unloading process therefore, the uppermost lift gas valve is passing gas under control from commands sent from surface equipment  44 , and the other lift gas valves are open to pass completion fluid but cannot yet be controlled. 
     Completion fluid continues to be expelled through the lower open valves until the completion fluid level reaches level  3 . The module  50  immediately above level  3  becomes powered and controllable as described with reference to the valve at level  2 , so that lift gas flow through the valve at level  3  may now be regulated by commands sent from the surface. Once this flow is established, the lift gas valve at level  2  may be closed, and lift of fluids in the tubing  34  is thus transferred from level  2  to level  3 . 
     In like manner, as the completion fluid continues to be expelled and its surface passes levels  4  and  5 , the gas lift valves at these levels become powered and controllable at progressively greater depths. As gas lift progresses down the tubing, the valves above are closed to conserve lift gas, which is directed to only the lowermost lifting valve. At the end of the unloading process, only the gas lift valve at choke  32  is open, and all valves above it are closed. 
     This method for controlling the unloading process ensures that each valve is closed at the correct moment. In existing practice and without benefit of means to control directly the lift gas valves, the cycling of the intermediate valves between open and closed is implemented by using pre-set opening and closing pressures. These preset values are chosen using design calculations which are based on incomplete or uncertain data. The consequence is that in existing practice the valves frequently open and close at inappropriate times, causing lift instability, excessive wear or total destruction of the valves, and also inefficiencies in lift gas usage from the need to specify the valve presets with pressure margins which reduce the range of gas pressures which can be made available for lift during the unloading and production processes. 
     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 the gas into the tubing section and the rise of the fluid column within the tubing to the surface. Such mechanical gas-lift valves are typically mechanical bellows-type devices (see FIG. 1) that open and close when the fluid pressure exceeds the pre-charge in the bellows section. Unfortunately, a leak in the bellows is common and renders the bellows-type valve largely inoperative once the bellows pressure departs from its pre-charge setting unless the bellows fails completely, i.e. rupture, in which case the valve fails closed and is totally inoperative. Further, a common source of failure in such bellows-type valve is the erosion and deterioration of the ball valve against the seat as the ball and seat contact frequently during normal operation in the often briney, high temperature, and high pressure conditions around the ball valve. Such leaks and failures are not readily detectable at the surface and probably reduce a well&#39;s production efficiency on the order of 15 percent through lower production rates and higher demands on the field lift gas compression systems. 
     The controllable gas-lift well of the present invention has a number of data monitoring pods and controllable gas-lift valves on the tubing string, the number and type of each pod and controllable valves depends on the requirements of the individual well. Each of the individual data monitoring pods and controllable valves is individually addressable via wireless spread spectrum communication through the tubing and casing. That is, a master spread spectrum modem at the surface and an associated controller communicates to a number of slave modems. The data monitoring pods 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. 6, sensors  112 ,  114 ,  116 , and  118 ). Such data is similarly communicated to the surface through a slave spread spectrum modem communicating through the tubing and casing. 
     The surface computer (either local or centrally located) 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. Preferably, pressure measurements are taken at locations uninfluenced by gas-lift injection turbulence. Acoustic sensors (sounds less than approximately 20 kilohertz) listen for tubing bubble patterns. Data is sent via the slave modem directly to the surface controller. Alternatively, data can be sent to a mid-hole data monitoring pod and relayed to the surface computer. 
     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 most desirable flow regime. By being able to determine such unwanted bubble flow conditions quickly downhole, production can be controlled to avoid such unwanted conditions. A fast detection of flow conditions allows the correction of 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 rebar in a concrete dam or a street 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. 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.

Technology Classification (CPC): 4