Abstract:
A petroleum well having a well casing, a production tubing, a source of time-varying current, a downhole chemical injection device, and a downhole induction choke. The casing extends within a wellbore of the well. The tubing extends within the casing. The current source is located at the surface. The current source is electrically connected to, and adapted to output a time-varying current into, the tubing and/or the casing, which act as electrical conductors for providing downhole power and/or communications. The injection device having a communications and control module, a chemical container, and an electrically controllable chemical injector. The communications and control module is electrically connected to the tubing and/or the casing. The chemical injector is electrically connected to the communications and control module, and is in fluid communication with the chemical container. The downhole induction choke is located about a portion of the tubing and/or the casing. The chemical injector is electrically connected to the communications and control module, and is in fluid communication with the chemical container. The downhole induction choke is located about a portion of the tubing and/or the casing. The induction choke is adapted to route part of the electrical current through the communications and control module by creating a voltage potential between one side of the induction choke and another side of the induction choke. The communications and control module is electrically connected across the voltage potential. Also, a method is provided for controllably injecting a chemical into the well downhole, which may be used to: improve lift efficiency with a foaming agent, prevent deposition of solids with a paraffin solvent, improve a flow characteristic of the flow stream with a surfactant, prevent corrosion with a corrosion inhibitor, and/or prevent scaling with scale preventers.

Description:
CROSS-REFERENCES TO RELATED APPLICATIONS  
       [0001]    This application claims the benefit of the following U.S. Provisional Applications, all of which are hereby incorporated by reference:  
                                                 COMMONLY OWNED AND PREVIOUSLY FILED       U.S. PROVISIONAL PATENT APPLICATIONS            T &amp; K #   Serial Number   Title   Filing Date               TH 1599   60/177,999   Toroidal Choke Inductor for Wireless Communication   Jan. 24, 2000               and Control       TH 1600   60/178,000   Ferromagnetic Choke in Wellhead   Jan. 24, 2000       TH 1602   60/178,001   Controllable Gas-Lift Well and Valve   Jan. 24, 2000       TH 1603   60/177,883   Permanent, Downhole, Wireless, Two-Way Telemetry   Jan. 24, 2000               Backbone Using Redundant Repeater, Spread               Spectrum Arrays       TH 1668   60/177,998   Petroleum Well Having Downhole Sensors,   Jan. 24, 2000               Communication, and Power       TH 1669   60/177,997   System and Method for Fluid Flow Optimization   Jan. 24, 2000       TS 6185   60/181,322   A Method and Apparatus for the Optimal   Feb. 9, 2000               Predistortion of an Electromagnetic Signal in a               Downhole Communications System       TH 1599x   60/186,376   Toroidal Choke Inductor for Wireless Communication   Mar. 2, 2000               and Control       TH 1600x   60/186,380   Ferromagnetic Choke in Wellhead   Mar. 2, 2000       TH 1601   60/186,505   Reservoir Production Control from Intelligent Well   Mar. 2, 2000               Data       TH 1671   60/186,504   Tracer Injection in a Production Well   Mar. 2, 2000       TH 1672   60/186,379   OilweIl Casing Electrical Power Pick-Off Points   Mar. 2, 2000       TH 1673   60/186,394   Controllable Production Well Packer   Mar. 2, 2000       TH 1674   60/186,382   Use of Downhole High Pressure Gas in a Gas Lift   Mar. 2, 2000               Well       TH 1675   60/186,503   Wireless Smart Well Casing   Mar. 2, 2000       TH 1677   60/186,527   Method for Downhole Power Management Using   Mar. 2, 2000               Energization from Distributed Batteries or Capacitors               with Reconfigurable Discharge       TH 1679   60/186,393   Wireless Downhole Well Interval Inflow and   Mar. 2, 2000               Injection Control       TH 1681   60/186,394   Focused Through-Casing Resistivity Measurement   Mar. 2, 2000       TH 1704   60/186,531   Downhole Rotary Hydraulic Pressure for Valve   Mar. 2, 2000               Actuation       TH 1705   60/186,377   Wireless Downhole Measurement and Control For   Mar. 2, 2000               Optimizing Gas Lift Well and Field Performance       TH 1722   60/186,381   Controlled Downhole Chemical Injection   Mar. 2, 2000       TH 1723   60/186,378   Wireless Power and Communications Cross-Bar   Mar. 2, 2000               Switch                  
 
         [0002]    The current application shares some specification and figures with the following commonly owned and concurrently filed applications, all of which are hereby incorporated by reference:  
                                                 COMMONLY OWNED AND CONCURRENTLY FILED U.S PATENT APPLICATIONS            T &amp; K #   Serial Number   Title   Filing Date               TH 1601US   09/ —     Reservoir Production Control from Intelligent Well                   Data       TH 1671US   09/ —     Tracer Injection in a Production Well       TH 1672US   09/ —     Oil Well Casing Electrical Power Pick-Off Points       TH 1673US   09/ —     Controllable Production Well Packer       TH 1674US   09/ —     Use of Downhole High Pressure Gas in a Gas-Lift               Well       TH 1675US   09/ —     Wireless Smart Well Casing       TH 1677US   09/ —     Method for Downhole Power Management Using               Energization from Distributed Batteries or               Capacitors with Reconfigurable Discharge       TH 1679US   09/ —     Wireless Downhole Well Interval Inflow and               Injection Control       TH 1681US   09/ —     Focused Through-Casing Resistivity Measurement       TH 1704US   09/ —     Downhole Rotary Hydraulic Pressure for Valve               Actuation       TH 1705US   09/ —     Wireless Downhole Measurement and Control For               Optimizing Gas Lift Well and Field Performance       TH 1723US   09/ —     Wireless Power and Communications Cross-Bar               Switch                  
 
         [0003]    The current application shares some specification and figures with the following commonly owned and previously filed applications, all of which are hereby incorporated by reference:  
                                                               COMMONLY OWNED AND PREVIOUSLY FILED U.S PATENT APPLICATIONS            T &amp; K #   Serial Number   Title   Filing Date                    TH 1599US   09/ —     Choke Inductor for Wireless Communication and               Control       TH 1600US   09/ —     Induction Choke for Power Distribution in Piping               Structure       TH 1602US   09/ —     Controllable Gas-Lift Well and Valve       TH 1603US   09/ —     Permanent Downhole, Wireless, Two-Way               Telemetry Backbone Using Redundant Repeater       TH 1668US   09/ —     Petroleum Well Having Downhole Sensors,               Communication, and Power       TH 1669US   09/ —     System and Method for Fluid Flow Optimization       TH 1783US   09/ —     Downhole Motorized Flow Control Valve       TS 6185US   09/ —     A Method and Apparatus for the Optimal               Predistortion of an Electro Magnetic Signal in a               Downhole Communications System                  
 
         [0004]    The benefit of 35 U.S.C. § 120 is claimed for all of the above referenced commonly owned applications. The applications referenced in the tables above are referred to herein as the “Related Applications.” 
     
    
     
       BACKGROUND OF THE INVENTION  
         [0005]    1. Field of the Invention  
           [0006]    The present invention relates to a petroleum well for producing petroleum products. In one aspect, the present invention relates to systems and methods for monitoring and/or improving fluid flow during petroleum production by controllably injecting chemicals into at least one fluid flow stream with at least one electrically controllable downhole chemical injection system of a petroleum well.  
           [0007]    2. Description of Related Art  
           [0008]    The controlled injection of materials into petroleum wells (i.e., oil and gas wells) is an established practice frequently used to increase recovery, or to analyze production conditions.  
           [0009]    It is useful to distinguish between types of injection, depending on the quantities of materials that will be injected. Large volumes of injected materials are injected into formations to displace formation fluids towards producing wells. The most common example is water flooding.  
           [0010]    In a less extreme case, materials are introduced downhole into a well to effect treatment within the well. Examples of these treatments include: (1) foaming agents to improve the efficiency of artificial lift; (2) paraffin solvents to prevent deposition of solids onto the tubing; and (3) surfactants to improve the flow characteristics of produced fluids. These types of treatment entail modification of the well fluids themselves. Smaller quantities are needed, yet these types of injection are typically supplied by additional tubing routed downhole from the surface.  
           [0011]    Still other applications require even smaller quantities of materials to be injected, such as: (1) corrosion inhibitors to prevent or reduce corrosion of well equipment; (2) scale preventers to prevent or reduce scaling of well equipment; and (3) tracer chemicals to monitor the flow characteristics of various well sections. In these cases the quantities required are small enough that the materials may be supplied from a downhole reservoir, avoiding the need to run supply tubing downhole from the surface. However, successful application of such techniques requires controlled injection.  
           [0012]    The controlled injection of materials such as water, foaming agents, paraffin solvents, surfactants, corrosion inhibitors, scale preventers, and tracer chemicals to monitor flow characteristics are documented in U.S. Pat. Nos. 4,681,164, 5,246,860, and 4, 068,717.  
           [0013]    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.  
         BRIEF SUMMARY OF THE INVENTION  
         [0014]    The problems and needs outlined above are largely solved and met by the present invention. In accordance with one aspect of the present invention, a chemical injection system for use in a well, is provided. The chemical injection system comprises a current impedance device and an electrically controllable chemical injection device. The current impedance device is generally configured for concentric positioning about a portion of a piping structure of the well. When a time-varying electrical current is transmitted through and along the portion of the piping structure, a voltage potential forms between one side of the current impedance device and another side of the current impedance device. The electrically controllable chemical injection device is adapted to be electrically connected to the piping structure across the voltage potential formed by the current impedance device, adapted to be powered by said electrical current, and adapted to expel a chemical into the well in response to an electrical signal.  
           [0015]    In accordance with another aspect of the present invention, a petroleum well for producing petroleum products, is provided. The petroleum well comprises a piping structure, a source of time-varying current, an induction choke, an electrically controllable chemical injection device, and an electrical return. The piping structure comprises a first portion, a second portion, and an electrically conductive portion extending in and between the first and second portions. The first and second portions are distally spaced from each other along the piping structure. The source of time-varying current is electrically connected to the electrically conductive portion of the piping structure at the first portion. The induction choke is located about a portion of the electrically conductive portion of the piping structure at the second portion. The electrically controllable chemical injection device comprises two device terminals, and is located at the second portion. The electrical return electrically connects between the electrically conductive portion of the piping structure at the second portion and the current source. The first of the device terminals is electrically connected to the electrically conductive portion of the piping structure on a source-side of the induction choke. The second of the device terminals is electrically connected to the electrically conductive portion of the piping structure on an electrical-return-side of the induction choke and/or the electrical return.  
           [0016]    In accordance with yet another aspect of the present invention, a petroleum well for producing petroleum products, is provided. The petroleum well comprises a well casing, a production tubing, a source of time-varying current, a downhole chemical injection device, and a downhole induction choke. The well casing extends within a wellbore of the well. The production tubing extends within the casing. The source of time-varying current is located at the surface. The current source is electrically connected to, and adapted to output a time-varying current into, the tubing and/or the casing, which act as electrical conductors to a downhole location. The downhole chemical injection device comprises a communications and control module, a chemical container, and an electrically controllable chemical injector. The communications and control module is electrically connected to the tubing and/or the casing. The chemical injector is electrically connected to the communications and control module, and is in fluid communication with the chemical container. The downhole induction choke is located about a portion of the tubing and/or the casing. The induction choke is adapted to route part of the electrical current through the communications and control module by creating a voltage potential between one side of the induction choke and another side of the induction choke. The communications and control module is electrically connected across the voltage potential.  
           [0017]    In accordance with still another aspect of the present invention, a method of producing petroleum products from a petroleum well, is provided. The method comprises the steps of: (i) providing a well casing extending within a wellbore of the well and a production tubing extending within the casing, wherein the casing is electrically connected to the tubing at a downhole location; (ii) providing a downhole chemical injection system for the well comprising an induction choke and an electrically controllable chemical injection device, the induction choke being located downhole about the tubing and/or the casing such that when a time-varying electrical current is transmitted through the tubing and/or the casing, a voltage potential forms between one side of the induction choke and another side of the induction choke, the electrically controllable chemical injection device being located downhole, the injection device being electrically connected to the tubing and/or the casing across the voltage potential formed by the induction choke such that the injection device can be powered by the electrical current, and the injection device being adapted to expel a chemical in response to an electrical signal carried by the electrical current; and (iii) controllably injecting a chemical into a downhole flow stream within the well during production. If the well is a gas-lift well and the chemical comprises a foaming agent, the method may further comprise the step of improving an efficiency of artificial lift of the petroleum productions with the foaming agent. If the chemical comprises a paraffin solvent, the method may further comprise the step of preventing deposition of solids on an interior of the tubing. If the chemical comprises a surfactant, the method may further comprise the step of improving a flow characteristic of the flow stream. If the chemical comprises a corrosion inhibitor, the method may further comprise the step of inhibiting corrosion in said well. If the chemical comprises scale preventers, the method may further comprise the step of reducing scaling in said well. 
       
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       [0018]    Other objects and advantages of the invention will become apparent upon reading the following detailed description and upon referencing the accompanying drawings, in which:  
         [0019]    [0019]FIG. 1 is a schematic showing a petroleum production well in accordance with a preferred embodiment of the present invention;  
         [0020]    [0020]FIG. 2 is an enlarged view of a downhole portion of the well in FIG. 1;  
         [0021]    [0021]FIG. 3 is a simplified electrical schematic of the electrical circuit formed by the well of FIG. 1; and  
         [0022]    FIGS.  4 A- 4 F are schematics of various chemical injector and chemical container embodiments for a downhole electrically controllable chemical injection device in accordance with the present invention. 
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0023]    Referring now to the drawings, wherein like reference numbers are used herein to designate like elements throughout the various views, a preferred embodiment of the present invention is illustrated and further described, and other possible embodiments of the present invention are described. The figures are not necessarily drawn to scale, and in some instances the drawings have been exaggerated and/or simplified in places for illustrative purposes only. One of ordinary skill in the art will appreciate the many possible applications and variations of the present invention based on the following examples of possible embodiments of the present invention, as well as based on those embodiments illustrated and discussed in the Related Applications, which are incorporated by reference herein to the maximum extent allowed by law.  
         [0024]    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 similar structures known to one of ordinary skill in the art. A preferred embodiment makes use of the invention in the context of a petroleum 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 portion where a power source is electrically connected to a second portion 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 portion of the piping structure to a second portion of the piping structure, wherein the first portion is distally spaced from the second portion along the piping structure.  
         [0025]    The terms “first portion” and “second portion” as used herein are each defined generally to call out a portion, section, or region of a piping structure that may or may not extend along the piping structure, that can be located at any chosen place along the piping structure, and that may or may not encompass the most proximate ends of the piping structure.  
         [0026]    The term “modem” is used herein to generically refer to any communications device for transmitting and/or receiving electrical communication signals via an electrical conductor (e.g., metal). Hence, the term “modem” as used herein 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 be modulated (e.g., spread spectrum modulation) and transmitted—hence no analog/digital conversion needed. As another example, a relay/slave modem or communication device may only need to identify, filter, amplify, and/or retransmit a signal received.  
         [0027]    The term “valve” as used herein generally refers to 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 and/or external 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.  
         [0028]    The term “electrically controllable valve” as used herein generally refers to a “valve” (as just described) that can be opened, closed, adjusted, altered, or throttled continuously in response to an electrical control signal (e.g., signal from a surface computer or from a downhole electronic controller module). The mechanism that actually moves the valve position can comprise, but is not limited to: an electric motor; an electric servo; an electric solenoid; an electric switch; a hydraulic actuator controlled by at least one electrical servo, electrical motor, electrical switch, electric solenoid, or combinations thereof; a pneumatic actuator controlled by at least one electrical servo, electrical motor, electrical switch, electric solenoid, or combinations thereof; or a spring biased device in combination with at least one electrical servo, electrical motor, electrical switch, electric solenoid, or combinations thereof. An “electrically controllable valve” may or may not include a position feedback sensor for providing a feedback signal corresponding to the actual position of the valve.  
         [0029]    The term “sensor” as used herein refers to any device that detects, determines, monitors, records, or otherwise senses the absolute value of or a change in a physical quantity. A sensor as described herein can be used to measure physical quantities including, but not limited to: temperature, pressure (both absolute and differential), flow rate, seismic data, acoustic data, pH level, salinity levels, valve positions, or almost any other physical data.  
         [0030]    As used in the present application, “wireless” 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.” 
         [0031]    The phrase “at the surface” as used herein refers to a location that is above about fifty feet deep within the Earth. In other words, the phrase “at the surface” does not necessarily mean sitting on the ground at ground level, but is used more broadly herein to refer to a location that is often easily or conveniently accessible at a wellhead where people may be working. For example, “at the surface” can be on a table in a work shed that is located on the ground at the well platform, it can be on an ocean floor or a lake floor, it can be on a deep-sea oil rig platform, or it can be on the 100th floor of a building. Also, the term “surface” may be used herein as an adjective to designate a location of a component or region that is located “at the surface.” For example, as used herein, a “surface” computer would be a computer located “at the surface.” 
         [0032]    The term “downhole” as used herein refers to a location or position below about fifty feet deep within the Earth. In other words, “downhole” is used broadly herein to refer to a location that is often not easily or conveniently accessible from a wellhead where people may be working. For example in a petroleum well, a “downhole” location is often at or proximate to a subsurface petroleum production zone, irrespective of whether the production zone is accessed vertically, horizontally, lateral, or any other angle therebetween. Also, the term “downhole” is used herein as an adjective describing the location of a component or region. For example, a “downhole” device in a well would be a device located “downhole,” as opposed to being located “at the surface.” 
         [0033]    Similarly, in accordance with conventional terminology of oilfield practice, the descriptors “upper,” “lower,” “uphole,” and “downhole” are relative and refer to distance along hole depth from the surface, which in deviated or horizontal wells may or may not accord with vertical elevation measured with respect to a survey datum.  
         [0034]    [0034]FIG. 1 is a schematic showing a petroleum production well  20  in accordance with a preferred embodiment of the present invention. The well  20  has a vertical section  22  and a lateral section  26 . The well has a well casing  30  extending within wellbores and through a formation  32 , and a production tubing  40  extends within the well casing for conveying fluids from downhole to the surface during production. Hence, the petroleum production well  20  shown in FIG. 1 is similar to a conventional well in construction, but with the incorporation of the present invention.  
         [0035]    The vertical section  22  in this embodiment incorporates a gas-lift valve  42  and an upper packer  44  to provide artificial lift for fluids within the tubing  40 . However, in alternative, other ways of providing artificial lift may be incorporated to form other possible embodiments (e.g., rod pumping). Also, the vertical portion  22  can further vary to form many other possible embodiments. For example in an enhanced form, the vertical portion  22  may incorporate one or more electrically controllable gas-lift valves, one or more additional induction chokes, and/or one or more controllable packers comprising electrically controllable packer valves, as further described in the Related Applications.  
         [0036]    The lateral section  26  of the well  20  extends through a petroleum production zone  48  (e.g., oil zone) of the formation  32 . The casing  30  in the lateral section  26  is perforated to allow fluids from the production zone  48  to flow into the casing. FIG. 1 shows only one lateral section  26 , but there can be many lateral branches of the well  20 . The well configuration typically depends, at least in part, on the layout of the production zones for a given formation.  
         [0037]    Part of the tubing  40  extends into the lateral section  26  and terminates with a closed end  52  past the production zone  48 . The position of the tubing end  52  within the casing  30  is maintained by a lateral packer  54 , which is a conventional packer. The tubing  40  has a perforated section  56  for fluid intake from the production zone  48 . In other embodiments (not shown), the tubing  40  may continue beyond the production zone  48  (e.g., to other production zones), or the tubing  40  may terminate with an open end for fluid intake. An electrically controllable downhole chemical injection device  60  is connected inline on the tubing  40  within the lateral section  26  upstream of the production zone  48  and forms part of the production tubing assembly. In alternative, the injection device  60  may be placed further upstream within the lateral section  26 . An advantage of placing the injection device  60  proximate to the tubing intake  56  at the production zone  48  is that it a desirable location for injecting a tracer (to monitor the flow into the tubing at this production zone) or for injecting a foaming agent (to enhance gas-lift performance). In other possible embodiments, the injection device  60  may be adapted to controllably inject a chemical or material at a location outside of the tubing  40  (e.g., directly into the producing zone  48 , or into an annular space  62  within the casing  30 ). Also, an electrically controllable downhole chemical injection device  60  may be placed in any downhole location within a well where it is needed.  
         [0038]    An electrical circuit is formed using various components of the well  20 . Power for the electrical components of the injection device  60  is provided from the surface using the tubing  40  and casing  30  as electrical conductors. Hence, in a preferred embodiment, the tubing  40  acts as a piping structure and the casing  30  acts as an electrical return to form an electrical circuit in the well  20 . Also, the tubing  40  and casing  30  are used as electrical conductors for communication signals between the surface (e.g., a surface computer system) and the downhole electrical components within the electrically controllable downhole chemical injection device  60 .  
         [0039]    In FIG. 1, a surface computer system  64  comprises a master modem  66  and a source of time-varying current  68 . But, as will be clear to one of ordinary skill in the art, the surface equipment can vary. A first computer terminal  71  of the surface computer system  64  is electrically connected to the tubing  40  at the surface, and imparts time-varying electrical current into the tubing  40  when power to and/or communications with the downhole devices is needed. The current source  68  provides the electrical current, which carries power and communication signals downhole. The time-varying electrical current is preferably alternating current (AC), but it can also be a varying direct current (DC). The communication signals can be generated by the master modem  66  and embedded within the current produced by the source  68 . Preferably, the communication signal is a spread spectrum signal, but other forms of modulation or pre-distortion can be used in alternative.  
         [0040]    A first induction choke  74  is located about the tubing in the vertical section  22  below the location where the lateral section  26  extends from the vertical section. A second induction choke  90  is located about the tubing  40  within the lateral section  26  proximate to the injection device  60 . The induction chokes  74 ,  90  comprise a ferromagnetic material and are unpowered. Because the chokes  74 ,  90  are located about the tubing  40 , each choke acts as a large inductor to AC in the well circuit formed by the tubing  40  and casing  30 . As described in detail in the Related Applications, the chokes  74 ,  90  function based on their size (mass), geometry, and magnetic properties.  
         [0041]    An insulated tubing joint  76  is incorporated at the wellhead to electrically insulate the tubing  40  from casing  30 . The first computer terminal  71  from the current source  68  passes through an insulated seal  77  at the hanger  88  and electrically connects to the tubing  40  below the insulated tubing joint  76 . A second computer terminal  72  of the surface computer system  64  is electrically connected to the casing  30  at the surface. Thus, the insulators  79  of the tubing joint  76  prevent an electrical short circuit between the tubing  40  and casing  30  at the surface. In alternative to or in addition to the insulated tubing joint  76 , a third induction choke (not shown) can be placed about the tubing  40  above the electrical connection location for the first computer terminal  71  to the tubing, and/or the hanger  88  may be an insulated hanger (not shown) having insulators to electrically insulate the tubing  40  from the casing  30 .  
         [0042]    The lateral packer  54  at the tubing end  52  within the lateral section  26  provides an electrical connection between the tubing  40  and the casing  30  downhole beyond the second choke  90 . A lower packer  78  in the vertical section  22 , which is also a conventional packer, provides an electrical connection between the tubing  40  and the casing  30  downhole below the first induction choke  74 . The upper packer  44  of the vertical section  22  has an electrical insulator  79  to prevent an electrical short circuit between the tubing  40  and the casing  30  at the upper packer. Also, various centralizers (not shown) having electrical insulators to prevent shorts between the tubing  40  and casing  30  can be incorporated as needed throughout the well  20 . Such electrical insulation of the upper packer  44  or a centralizer may be achieved in various ways apparent to one of ordinary skill in the art. The upper and lower packers  44 ,  78  provide hydraulic isolation between the main wellbore of the vertical section  22  and the lateral wellbore of the lateral section  26 .  
         [0043]    [0043]FIG. 2 is an enlarged view showing a portion of the lateral section  26  of FIG. 1 with the electrically controllable downhole chemical injection device  60  therein. The injection device  60  comprises a communications and control module  80 , a chemical container  82 , and an electrically controllable chemical injector  84 . Preferably, the components of an electrically controllable downhole chemical injection device  60  are all contained in a single, sealed tubing pod  86  together as one module for ease of handling and installation, as well as to protect the components from the surrounding environment. However, in other embodiments of the present invention, the components of an electrically controllable downhole chemical injection device  60  can be separate (i.e., no tubing pod  86 ) or combined in other combinations. A first device terminal  91  of the injection device  60  electrically connects between the tubing  40  on a source-side  94  of the second induction choke  90  and the communications and control module  80 . A second device terminal  92  of the injection device  60  electrically connects between the tubing  40  on an electrical-return-side  96  of the second induction choke  90  and the communications and control module  80 . Although the lateral packer  54  provides an electrical connection between the tubing  40  on the electrical-return-side  96  of the second induction  90  and the casing  30 , the electrical connection between the tubing  40  and the well casing  30  also can be accomplished in numerous ways, some of which can be seen in the Related Applications, including (but not limited to): another packer (conventional or controllable); a conductive centralizer; conductive fluid in the annulus between the tubing and the well casing; or any combination thereof.  
         [0044]    [0044]FIG. 3 is a simplified electrical schematic illustrating the electrical circuit formed in the well  20  of FIG. 1. In operation, power and/or communications are imparted into the tubing  40  at the surface via the first computer terminal  71  below the insulated tubing joint  76 . Time-varying current is hindered from flowing from the tubing  40  to the casing  30  via the hanger  88  due to the insulators  79  of the insulated tubing joint  76 . However, the time-varying current flows freely along the tubing  40  until the induction chokes  74 ,  90  are encountered. The first induction choke  74  provides a large inductance that impedes most of the current from flowing through the tubing  40  at the first induction choke. Similarly, the second induction choke  90  provides a large inductance that impedes most of the current from flowing through the tubing  40  at the second induction choke. A voltage potential forms between the tubing  40  and casing  30  due to the induction chokes  74 ,  90 . The voltage potential also forms between the tubing  40  on the source-side  94  of the second induction choke  90  and the tubing  40  on the electrical-return-side  96  of the second induction choke  90 . Because the communications and control module  80  is electrically connected across the voltage potential, most of the current imparted into the tubing  40  that is not lost along the way is routed through the communications and control module  80 , which distributes and/or decodes the power and/or communications for the injection device  60 . After passing through the injection device  60 , the current returns to the surface computer system  64  via the lateral packer  54  and the casing  30 . When the current is AC, the flow of the current just described will also be reversed through the well  20  along the same path.  
         [0045]    Other alternative ways to develop an electrical circuit using a piping structure of a well and at least one induction choke are described in the Related Applications, many of which can be applied in conjunction with the present invention to provide power and/or communications to the electrically powered downhole devices and to form other embodiments of the present invention.  
         [0046]    Referring to FIG. 2 again, the communications and control module  80  comprises an individually addressable modem  100 , power conditioning circuits  102 , a control interface  104 , and a sensors interface  106 . Sensors  108  within the injection device  60  make measurements, such as flow rate, temperature, pressure, or concentration of tracer materials, and these data are encoded within the communications and control module  80  and transmitted by the modem  100  to the surface computer system  64 . Because the modem  100  of the downhole injection device  60  is individually addressable, more than one downhole device may be installed and operated independently of others.  
         [0047]    In FIG. 2, the electrically controllable chemical injector  84  is electrically connected to the communications and control module  80 , and thus obtains power and/or communications from the surface computer system  64  via the communications and control module  80 . The chemical container  82  is in fluid communication with the chemical injector  84 . The chemical container  82  is a self-contained chemical reservoir that stores and supplies chemicals for injecting into the flow stream by the chemical injector. The chemical container  82  of FIG. 2 is not supplied by a chemical supply tubing extending from the surface. Hence, the size of the chemical container may vary, depending on the volume of chemicals needed for the injecting into the well. Indeed, the size of the chemical container  82  may be quite large if positioned in the “rat hole” of the well. The chemical injector  84  of a preferred embodiment comprises an electric motor  110 , a screw mechanism  112 , and a nozzle  114 . The electric motor  110  is electrically connected to and receives motion command signals from the communications and control module  80 . The nozzle  114  extends into an interior  116  of the tubing  40  and provides a fluid passageway from the chemical container  82  to the tubing interior  116 . The screw mechanism  112  is mechanically coupled to the electric motor  110 . The screw mechanism  112  is used to drive chemicals out of the container  82  and into the tubing interior  116  via the nozzle  114  in response to a rotational motion of the electric motor  110 . Preferably the electric motor  110  is a stepper motor, and thus provides chemical injection in incremental amounts.  
         [0048]    In operation, the fluid stream from the production zone  48  passes through the chemical injection device  60  as it flows through the tubing  40  to the surface. Commands from the surface computer system  64  are transmitted downhole and received by the modem  100  of the communications and control module  80 . Within the injection device  60  the commands are decoded and passed from the modem  100  to the control interface  104 . The control interface  104  then commands the electric motor  110  to operate and inject the specified quantity of chemicals from the container  82  into the fluid flow stream in the tubing  40 . Hence, the chemical injection device  60  injects a chemical into the fluid stream flowing within the tubing  40  in response to commands from the surface computer system  64  via the communications and control module  80 . In the case of a foaming agent, the foaming agent is injected into the tubing  40  by the chemical injection device  60  as needed to improve the flow and/or lift characteristics of the well  20 .  
         [0049]    As will be apparent to one of ordinary skill in the art, the mechanical and electrical arrangement and configuration of the components within the electrically controllable chemical injection device  60  can vary while still performing the same function—providing electrically controllable chemical injection downhole. For example, the contents of a communications and control module  80  may be as simple as a wire connector terminal for distributing electrical connections from the tubing  40 , or it may be very complex comprising (but not limited to) a modem, a rechargeable battery, a power transformer, a microprocessor, a memory storage device, a data acquisition card, and a motion control card.  
         [0050]    FIGS.  4 A- 4 G illustrate some possible variations of the chemical container  82  and chemical injector  84  that may be incorporated into the present invention to form other possible embodiments. In FIG. 4A, the chemical injector  84  comprises a pressurized gas reservoir  118 , a pressure regulator  120 , an electrically controllable valve  122 , and a nozzle  114 . The pressurized gas reservoir  118  is fluidly connected to the chemical container  82  via the pressure regulator  120 , and thus supplies a generally constant gas pressure to the chemical container. The chemical container  82  has a bladder  124  therein that contains the chemicals. The pressure regulator  120  regulates the passage of pressurized gas supplied from the pressurized gas reservoir  118  into the chemical container  82  but outside of the bladder  124 . However, the pressure regulator  120  may be substituted with an electrically controllable valve. The pressurized gas exerts pressure on the bladder  124  and thus on the chemicals therein. The electrically controllable valve  122  regulates and controls the passage of the chemicals through the nozzle  114  and into the tubing interior  116 . Because the chemicals inside the bladder  124  are pressurized by the gas from the pressurized gas reservoir  118 , the chemicals are forced out of the nozzle  114  when the electrically controllable valve  122  is opened.  
         [0051]    In FIG. 4B, the chemical container  82  is divided into two volumes  126 ,  128  by a bladder  124 , which acts a separator between the two volumes  126 ,  128 . A first volume  126  within the bladder  124  contains the chemical, and a second volume  128  within the chemical container  82  but outside of the bladder contains a pressurized gas. Hence, the container  82  is precharged and the pressurized gas exerts pressure on the chemical within the bladder  124 . The chemical injector  84  comprises an electrically controllable valve  122  and a nozzle  114 . The electrically controllable valve  122  is electrically connected to and controlled by the communications and control module  80 . The electrically controllable valve  122  regulates and controls the passage of the chemicals through the nozzle  114  and into the tubing interior  116 . The chemicals are forced out of the nozzle  114  due to the gas pressure when the electrically controllable valve  122  is opened.  
         [0052]    The embodiment shown in FIG. 4C is similar that of FIG. 4B, but the pressure on the bladder  124  is provided by a spring member  130 . Also in FIG. 4C, the bladder may not be needed if there is movable seal (e.g., sealed piston) between the spring member  130  and the chemical within the chemical container  82 . One of ordinary skill in the art will see that there can be many variations on the mechanical design of the chemical injector  84  and on the use of a spring member to provide pressure on the chemical.  
         [0053]    In FIG. 4D, the chemical container  82  is a pressurized bottle containing a chemical that is a pressurized fluid. The chemical injector  84  comprises an electrically controllable valve  122  and a nozzle  114 . The electrically controllable valve  122  regulates and controls the passage of the chemicals through the nozzle  114  and into the tubing interior  116 . Because the chemicals inside the bottle  82  are pressurized, the chemicals are forced out of the nozzle  114  when the electrically controllable valve  122  is opened.  
         [0054]    In FIG. 4E, the chemical container  82  has a bladder  124  containing a chemical. The chemical injector  84  comprises a pump  134 , a one-way valve  136 , a nozzle  114 , and an electric motor  110 . The pump  134  is driven by the electric motor  110 , which is electrically connected to and controlled by the communications and control module  80 . The one-way valve  136  prevents backflow into the pump  134  and bladder  124 . The pump  134  drives chemicals out of the bladder  124 , through the one-way valve  136 , out of the nozzle  114 , and into the tubing interior  116 . Hence, the use of the chemical injector  84  of FIG. 4E may be advantageous in a case where the chemical reservoir or container  82  is arbitrarily shaped to maximize the volume of chemicals held therein for a given configuration because the chemical container configuration is not dependent on chemical injector  84  configuration implemented.  
         [0055]    [0055]FIG. 4F shows an embodiment of the present invention where a chemical supply tubing  138  is routed downhole to the chemical injection device  60  from the surface. Such an embodiment may be used in a case where there is a need to inject larger quantities of chemicals into the tubing interior  116 . The chemical container  82  of FIG. 4F provides both a fluid passageway connecting the chemical supply tubing  138  to the chemical injector  84 , and a chemical reservoir for storing some chemicals downhole. Also, the downhole container  82  may be only a fluid passageway or connector (no reservoir volume) between the chemical supply tubing  138  and the chemical injector  84  to convey bulk injection material from the surface as needed.  
         [0056]    Thus, as the examples in FIGS.  4 A- 4 F illustrate, there are many possible variations for the chemical container  82  and chemical injector  84 . One of ordinary skill in the art will see that there can be many more variations for performing the functions of supplying, storing, and/or containing a chemical downhole in combination with controllably injecting the chemical into the tubing interior  116  in response to an electrical signal. Variations (not shown) on the chemical injector  84  may further include (but are not limited to): a venturi tube at the nozzle; pressure on the bladder provided by a turbo device that extracts rotational energy from the fluid flow within the tubing; extracting pressure from other regions of the formation routed via a tubing; any possible combination of the parts of FIGS.  4 A- 4 F; or any combination thereof.  
         [0057]    Also, the chemical injection device  60  may not inject chemicals into the tubing interior  116 . In other words, a chemical injection device may be adapted to controllably inject a chemical into the formation  32 , into the casing  30 , or directly into the production zone  48 . Also, a tubing extension (not shown) may extend from the chemical injector nozzle to a region remote from the chemical injection device (e.g., further downhole, or deep into a production zone).  
         [0058]    The chemical injection device  60  may further comprise other components to form other possible embodiments of the present invention, including (but not limited to): a sensor, a modem, a microprocessor, a logic circuit, an electrically controllable tubing valve, multiple chemical reservoirs (which may contain different chemicals), or any combination thereof. The chemical injected may be a solid, liquid, gas, or mixtures thereof. The chemical injected may be a single component, multiple components, or a complex formulation. Furthermore, there can be multiple controllable chemical injection devices for one or more lateral sections, each of which may be independently addressable, addressable in groups, or uniformly addressable from the surface computer system  64 . In alternative to being controlled by the surface computer system  64 , the downhole electrically controllable injection device  60  can be controlled by electronics therein or by another downhole device. Likewise, the downhole electrically controllable injection device  60  may control and/or communicate with other downhole devices. In an enWO 01/65055 of an electrically controllable chemical injection device  60 , PCT/US01/06951e or more sensors  108 , each adapted to measure a physical quality such as (but not limited to): absolute pressure, differential pressure, fluid density, fluid viscosity, acoustic transmission or reflection properties, temperature, or chemical make-up.  
         [0059]    Upon review of the Related Applications, one of ordinary skill in the art will also see that there can be other electrically controllable downhole devices, as well as numerous induction chokes, further included in a well to form other possible embodiments of the present invention. Such other electrically controllable downhole devices include (but are not limited to): one or more controllable packers having electrically controllable packer valves, one or more electrically controllable gas-lift valves; one or more modems, one or more sensors; a microprocessor; a logic circuit; one or more electrically controllable tubing valves to control flow from various lateral branches; and other electronic components as needed.  
         [0060]    The present invention also may be applied to other types of wells (other than petroleum wells), such as a water production well.  
         [0061]    It will be appreciated by those skilled in the art having the benefit of this disclosure that this invention provides a petroleum production well having at least one electrically controllable chemical injection device, as well as methods of utilizing such devices to monitor and/or improve the well production. It should be understood that the drawings and detailed description herein are to be regarded in an illustrative rather than a restrictive manner, and are not intended to limit the invention to the particular forms and examples disclosed. On the contrary, the invention includes any further modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments apparent to those of ordinary skill in the art, without departing from the spirit and scope of this invention, as defined by the following claims. Thus, it is intended that the following claims be interpreted to embrace all such further modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments.