Abstract:
An apparatus and method is presented for establishing electrical connection to permanent downhole oilfield installations using an electrically insulated conducting casing. Current is caused to flow in the casing by a source on the surface connected to the casing. One or more permanent downhole installations are electrically connected to the casing, and the electrical connection to the casing is used to power the downhole installations. The downhole installations also inject a signal into the insulated casing that passes via the casing to a surface readout which detects and records the downhole signals.

Description:
BACKGROUND OF THE INVENTION 
     1. Technical Field 
     The present invention relates to monitoring and control of subsurface installations located in one or more reservoirs of fluids such as hydrocarbons, and more particularly to methods and installations for providing wireless transmission of power and communication signals to, and receiving communication signals from, those subsurface installations. 
     2. Related Background Art 
     Reservoir monitoring includes the process of acquiring reservoir data for purposes of reservoir management. Permanent monitoring techniques are frequently used for long-term reservoir management. In permanent monitoring, sensors are often permanently implanted in direct contact with the reservoir to be managed. Permanent installations have the benefit of allowing continuous monitoring of the reservoir without interrupting production from the reservoir and providing data when well re-entry is difficult, e.g. subsea completions. 
     Permanent downhole sensors are used in the oil industry for several applications. For example, in one application, sensors are permanently situated inside the casing to measure phenomenon inside the well such as fluid flow rates or pressure. 
     Another application is in combination with so-called smart or instrumented wells with downhole flow control. An exemplary smart or instrumented well system combines downhole pressure gauges, flow rate sensors and flow controlling devices placed within the casing to measure and record pressure and flow rate inside the well and adjust fluid flow rate to optimize well performance and reservoir behavior. 
     Other applications call for using sensors permanently situated in the cement annulus surrounding the well casing. In these applications, formation pressure is measured using cemented pressure gauges; distribution of water saturation away from the well using resistivity sensors in the cement annulus; and seismic or acoustic earth properties using cemented geophones. Appropriate instrumentation allows other parameters to be measured. 
     These systems utilize cables to provide power and/or signal connection between the downhole devices and the surface. The use of a cable extending from the surface to provide a direct to connection to the downhole devices presents a number of well known advantages. 
     There are however, a number of disadvantages associated with the use of a cable in the cement annulus connecting the downhole devices to the surface including: a cable outside the casing complicates casing installation; reliability problems are associated with connectors currently in use; there is a risk of the cable breaking; the cable needs to be regularly anchored to the casing with cable protectors; the presence of a cable in the cement annulus may increase the risk of an inadequate hydraulic seal between zones that must be isolated; added expense of modifications to the wellhead to accommodate the feed-through of large diameter multi-conductor cables; the cables can be damaged if they pass through a zone that is perforated and it is difficult to pass the cable across the connection of two casings of different diameters. 
     In efforts to alleviate these and other disadvantages of downhole cable use, so-called “wireless systems” have been developed. 
     Bottom electromagnetic telemetry allows for electrical signals to be injected into conductive casings to create an electrical dipole source at the bottom of the well in order to telemeter measurement data from the subsurface to the surface. A related idea uses currents in a casing segment downhole to establish a magnetic field in the earth, the latter used to steer another well being drilled. 
     Bottom switching as telemetry via casing and tubing or wireline utilizes various arrangements of an electrical switch downhole between casing and tubing, between casing and a wireline tool, or between two electrically isolated segments of casing to send downhole measurement data to a surface detection and recording system. 
     Tubing-Casing transmission (“TUCAS”), a wireless two-way communication system, developed and patented by Schlumberger (U.S. Pat. No. 4,839,644 which is incorporated herein by reference), in which an insulated system of tubing and casing serve as a coaxial line as illustrated in FIG.  1 . Both power and two-way signal (communication) transmission are possible in the TUCAS system. Because the system uses an inductive coupling technique to inject or retrieve power and signal from the system, only on the order of several tens of watts of power can be sent to the downhole sensor devices, which is adequate for commercial pressure gauge sensors. Additionally, electrical insulation between the tubing and casing must be maintained. 
     Likewise, shortcomings are evident in known systems where a toroid is used for current injection in casing or a drill string which is in contact with a surrounding cement annulus or earth formation. In addition to the limitations on the level of power which can be inductively coupled, the current loop will be local as the current return will seek the shortest electrical path through the formation to return to casing, as illustrated in FIG.  2 . 
     Another system using casing conductivity injects current for locally heating the formation to help move viscous hydrocarbon fluids. This system, as illustrated in FIG. 3, concentrates a large current into a minimal area resulting in localized high current density in the resistive earth, thereby generating heat. High current density is seen in heated zone H while very low current density is seen at surface return electrode R. 
     A simple surface return is utilized as there is no concern with overall system efficiency as far as electrical circulation is concerned. This type of system does not use the casing in conjunction with downhole electronics, i.e. for communication with or direct power transfer to downhole electronics, but rather focuses on the generation of heat in the formation via concentration of a large current flux at the end of the casing in zone H. Insulation is employed for current concentration in zone H by preventing injected current from flowing out of the casing to the surrounding formation except where desired—i.e., at the bottom of the well where the casing is exposed in zone H. 
     Several practical disadvantages are evident in such a system as that of FIG.  3 . One primary, and potentially dangerous disadvantage is that the wellhead is necessarily maintained at a very high potential in order to achieve the desired current density at well bottom to generate sufficient formation heating for their desired purposes. This can pose significant danger to the crew at the well site. 
     SUMMARY OF THE INVENTION 
     Limitations of the prior art are overcome by the method and apparatus of the present invention of power and signal transmission using insulated casing for permanent downhole installations as described hereinbelow. 
     The present invention is directed to various methods and apparatus for transmitting at least one electrical signal to or from at least one downhole device in a well. The method comprises providing an electrically conductive conduit in the well, electrically insulating a section of the conduit by encapsulating a section of the conduit with an insulative layer and insulating the encapsulated section of conduit from an adjoining section of the conduit by using a conduit gap, introducing the electrical signal within the insulated section of conduit, providing a return path for the electrical signal, and connecting the downhole device to the insulated section. 
     In alternative embodiments, the method includes introducing the electrical signal is performed via inductive coupling and/or direct coupling. The electrical signal includes power or communication signals. The electrical signals can be introduced by one of the downhole devices or by a surface device, directly or inductively coupled to the insulated section of conduit. The method may also include use of a second conduit gap to form a completely electrically insulated conduit section. In the various embodiments, single or multiple devices may be coupled to the insulated section of conduit. The return path for the electrical signal may be provided through the earth formation surrounding the well, through the cement annulus or through an outer conductive layer of the conductive conduit. An apparatus is also disclosed for transmitting at least one electrical signal to or from at least one downhole device in a well. In various embodiments, the apparatus comprises an electrically conductive conduit installed in the well, insulation means for electrically insulating a section of the conduit, the insulation means comprising an insulative encapsulation layer around the section of the conduit and a conduit gap insulating the insulated section of the conduit from an adjoining section of the conduit, means for introducing the electrical signal within the insulated section of the conduit, means for providing a return path for the electrical signal, and means for electrically connecting the downhole device to the insulated section of the conduit. In alternative embodiments, the apparatus comprises inductive coupling and/or direct coupling for introducing the electrical power or communication signals. The electrical signals can be introduced by one of the downhole devices or by a surface device, directly or inductively coupled to the insulated section of conduit. The apparatus may also comprise a second conduit gap to form a completely electrically insulated conduit section. In the various embodiments, single or multiple devices may be coupled to the insulated section of conduit. The return path for the electrical signal may be provided through the earth formation surrounding the well, through the cement annulus or through an outer conductive layer of the conductive conduit. 
     The foregoing and other features and advantages of the present invention will become more apparent in light of the following detailed description of exemplary embodiments thereof, as illustrated in the accompanying drawings. 
    
    
     BRIEF DESCRIPTION OF DRAWINGS 
     The following drawings are referenced in the detailed description which follows and are provided to facilitate a better understanding of the invention disclosed herein. 
     FIG. 1 illustrates a known wireless transmission apparatus. 
     FIG. 2 illustrates known behavior of induced current. 
     FIG. 3 illustrates a known apparatus for earth formation heating. 
     FIG. 4 illustrates one embodiment of the present invention using an insulated casing with direct uphole and inductive downhole coupling. 
     FIG. 5A illustrates an alternative embodiment of the present invention using an insulated casing with direct uphole and downhole coupling. 
     FIG. 5B illustrates the current path through the downhole device of FIG.  5 A. 
     FIG. 6 illustrates an alternative embodiment of the present invention using insulated casing and production tubing with direct uphole and downhole coupling. 
     FIG. 7 illustrates an alternative embodiment of the present invention implemented with casing and/or tubing of different diameters. 
     FIG. 8 illustrates an alternative embodiment of the present invention implemented in a well having a lateral well and casing and/or tubing of different diameters. 
     FIG. 9 illustrates one embodiment of the present invention using an insulated casing with inductive uphole and downhole coupling. 
     FIG. 10 illustrates one embodiment of the present invention where downhole devices are connected in series downhole through use of conduit gaps in the production tubing. 
     FIG. 11 illustrates an alternative embodiment of the present invention where multiple downhole devices are connected in parallel through use of conduit gaps in the production tubing. 
     FIG. 12A illustrates one embodiment of the present invention where multiple downhole devices are connected in series downhole through use of the conduit gap in the production tubing. 
     FIG. 12B illustrates the current path through the downhole device of FIG.  12 A. 
     FIG. 13 illustrates one embodiment of the present invention where multiple downhole devices are connected in series downhole through use of conduit gaps in the insulated casing. 
     FIG. 14 depicts an illustrative embodiment of the conduit gap of present invention. 
     FIG. 15 illustrates an alternative embodiment of the present invention using an outer conductive layer on the insulated casing and inductive downhole coupling. 
     FIG. 16 illustrates an alternative embodiment of the present invention using an outer conductive layer on the insulated casing and direct (parallel) downhole coupling. 
     FIG. 17 illustrates an alternative embodiment of the present invention using a highly conductive cement layer as the outer conductive layer on the insulated casing and direct (parallel) downhole coupling. 
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
     Shown in FIG. 4 is an illustrative embodiment of the present invention. 
     A well  1  (with direction of production flow in well indicated by arrow) is drilled into earth formation  10  and completed with an insulated conductive conduit  20  secured by a cement annulus  40 . While in this exemplary embodiment a production well is shown, the invention is equally applicable to other types of wells. 
     Conduit gap  11  is disposed within the conductive conduit so as to provide  2  electrical zones of the conduit I and II, above and below the gap, respectively. 
     In this embodiment, the conductive conduit is implemented as a casing string  22  including casing segments  22 A and  22 B, region A of the string  22  being insulated by insulative layer  30 . The 2 electrical zones are effected by providing an electrical “gap” between casing segments  22 A and  22 B where casing segment  22 A is electrically insulated from segment  22 B by the gap. To fully effect the electrical zones, insulative layer  30  should extend along casing segment  22 B beyond the gap  11  (i.e. to overlap segment  22 A) so as to electrically isolate adjacent casing segments  22 A and  22 B from each other at the point of joining and throughout region A. Details concerning conduit gap  11  follow in the discussion associated with FIG.  14 . 
     Above and below the electrically insulated region A of segment  22 B are exposed portions of casing, which form top and bottom electrode portions,  70 ,  72  respectively. These portions are exposed to allow electrical contact between these limited electrode portions of the casing and surrounding annulus  40  and earth  10 . 
     Surface equipment (including voltage source  24  and encoder/decoder  25 ) is connected to casing string  22  via lines  60  and  61  on either side of conduit gap  11 . The current is injected via line  60  directly into casing segment  22 B with a return connection on line  61  connected to casing segment  22 A. The injected current will flow along illustrative current lines  12  through casing segment  22 B, leaking into annulus  40  and earth formation  10  via bottom electrode  72  and seek a return path to casing segment  22 A through top (return) electrode  70  back to casing segment  22 A and to surface equipment via line  61 . 
     At an appropriate depth in the well, measurement devices are installed inside or outside the casing. Measurement devices, typically sensors, measure a signal, related to a physical property of the earth formation, well or reservoir, on either the interior or exterior of the casing. For illustrative purposes, measurement device  28  in FIG. 4 is shown installed outside casing  22 . 
     The downhole electronics in device  28  receive electrical power via induction from a toroidal transformer (“toroid”)  26  on the outside of the casing  22 , specifically casing segment  22 B. The aforementioned injected current flowing through the casing segment  22 B (here injected via line  60  as described above) inductively generates a voltage in the toroid  26  by known electromagnetic principles, used to power and communicate with the sensor. As is known, various signals (including power and communication) can be modulated on a single carrier current for transmission downhole via injection. Toroid  26  can be fitted and installed on a segment of casing  22  during casing manufacture, as can various measurement devices intended for permanent installation. 
     For communication to surface, the signal sensed by device  28  is encoded into a second alternating voltage in toroid  26  by downhole encoder circuit  27 , at a frequency distinct from that of the injected current. This second voltage induces a second current in-casing segment  22 B, which also flows along illustrative current lines  12  and is detected by a surface electronic detector  25  where it is recorded, stored or otherwise processed as required. 
     Although not shown, multiple measurement devices (of the same or different type) with encoding/decoding circuits, and/or multiple toroids may be placed at various points (vertically) along the insulated casing (i.e., throughout region A). This allows a multitude of measurement devices to be distributed along the length of the well to accomplish diverse measurements. The encoder/decoder circuit  27  of each measurement device may additionally be equipped with an addressable circuit that allows instructions to be sent to, and measurement signals received from, individually controllable measurement devices. 
     While a typical cement annulus  40  has conductive properties, special highly conductive formulations of cement can be used to increase the conductivity of the cement so as to provide a more conductive path for currents. The use of highly conductive cement formulations has the advantage of providing a return path with controllable electrical characteristics. Use of specially formulated highly conductive cement will aid in performance and efficiency but is not critical and typical cement can none-the-less be used. 
     As for all embodiments described herein, the permanently installed conductive conduit includes at least an inner conductive member and an outer insulative layer. The conductive member can be either: 1) traditional metallic, preferable non-magnetic, conductive casing; 2) conductive production tubing; or, 3) other conductive liner installed permanently (usually via cementing) downhole (such as those described with respect to FIGS. 15-17 hereinbelow). The conduit is circumferentially encapsulated by an insulating layer over a specified region. For illustrative purposes and without the intent of imposing limitation, the various embodiments discussed herein utilize conductive casing or a combination of casing and tubing as the conduit conductive member. The insulating layer can be ceramic, plastic, fiberglass or other material pre-applied to each casing section before it is shipped to the wellsite for installation or, alternatively, the insulating layer may be a coating, paint or wrapping pre-applied or to be applied on-site at the wellsite. A current source and return path are also provided as discussed with respect to the various embodiments herein. In the various embodiments herein, top and bottom electrode portions of the insulated conduit are exposed so as to allow the conductive conduit to electrically contact the surrounding cement annulus to provide a current source and return path. The principle of operation of the present invention remains unchanged regardless of the physical structure chosen as the conduit, the implementation of the insulating layer, the current source or return path. 
     FIG. 5A illustrates an alternative embodiment of the present invention where direct coupling is used for both current injection and connection to the downhole measurement device. 
     Similar to the embodiment of FIG. 4, the conduit is implemented as a casing string  22  including casing segments  22 A,  22 B and  22 C. Conduit gap  11  is placed within the casing string to provide electrical isolation between adjoining casing segments  22 A and  22 B. Second conduit gap  110  is located between adjoining casing segments  22 B and  22 C to provide electric zones I, II and III. The electric zones result from the electrical “gap” between casing segments  22 A and  22 B, and that between  22 B and  22 C, where casing segment  22 A is electrically insulated from segment  22 B by gap  11  and  22 B electrically insulated from  22 C by second gap  110 . The insulative layer  30  extends beyond each gap  11 ,  110  to completely electrically insulate casing segment  22 B. Current will flow through the conductive cement annulus  40  (and surrounding earth formation  10 ) between zone III and zone I (i.e., casing segments  22 C and  22 A) external to the insulated conductive conduit of region A. 
     Surface equipment (including voltage source  24  and encoder/decoder  25 ) is connected to the casing string  22  via a lines  60  and  61 . The current is injected via line  60  into casing segment  22 B with a return connection via line  61  connected to casing segment  22 A. 
     Communications with and power to device  28  are provided via direct connection of downhole device  28  to casing  22  as illustrated in FIG.  5 B. Device  28  and casing segments  22 B and  22 C are connected in series, with independent connections via leads  28 A and  28 B on either side of gap  110  to casing segments  22 B and  22 C, respectively. Current from casing segment  22 B will flow through device  28  to casing segment  22 C. 
     Referring again to FIG. 5A, the injected current will flow along illustrative current lines  12  through casing segment  22 B, through device  28  to  22 C, leaking into annulus  40  via bottom electrode  72  and seeking a return path to casing segment  22 A through top (return) electrode  70 . 
     The current injection connection, via line  60  to casing segment  22 B in both FIGS. 4 and 5A is achieved downhole locally within the insulated region A, below gap  11 . The return connection (via line  61  and casing segment  22 A in both FIGS.  4  and  5 A), on the other hand, can be achieved downhole or alternatively near the surface without any diminished performance as all casing segments above gap  11  back to the surface are electrically connected. Direct downhole casing connections such as discussed with respect to the embodiments of FIGS. 4 and 5A can be achieved in any suitable manner to assure good (i.e., low loss, efficient) electrical contact. One known technique is the use of landing devices. 
     FIG. 6 shows an alternative embodiment of the present invention where electrical connection for current injection is achieved via direct connection to the conductive conduit and production tubing. 
     Similar to the embodiment of FIG. 5A, the conductive conduit is implemented as a casing string  22  which includes casing segments  22 A,  22 B and  22 C. Conduit gap  11  is placed within the casing string to provide electrical isolation between adjoining casing segments  22 A and  22 B. Second conduit gap  110  is disposed between adjoining casing segments  22 B and  22 C providing electrical zones I, II and III. The electric zones result because of the electrical “gap” between casing segments  22 A and  22 B, and  22 B and  22 C, where casing segment  22 A is electrically insulated from segment  22 B by gap  11  and  22 B electrically insulated from  22 C by second gap  110 . The insulative layer  30  extends beyond each gap  11 ,  110  to completely electrically insulate casing segment  22 B. Current will flow through the conductive cement annulus  40  (and surrounding earth formation  10 ) between zone III and zone I (i.e., casing segments  22 C and  22 A) external to the insulated conductive conduit of region A. 
     Tubing  18  is electrically isolated from the zone I and III casing (i.e., the casing segments from surface down through and including  22 A and from and including  22 C down to well bottom) by any of several known techniques such as providing an insulative layer around the tubing or an insulative layer on the inside of the casing or non-conductive centralizers (not shown) can be deployed in zones I and III. Tubing  18  is electrically connected to zone II casing via appropriate means such as conductive packer  71 . Where insulated tubing is used the insulative layer must be traversed or removed at conductive packer  71  to allow for electrical contact with the casing (i.e., in the illustration, casing segment  22 B). 
     Surface equipment (including voltage source  24  and encoder/decoder  25 ) is connected to the tubing  18  via line  60  and to zone I casing string via line  61 . The current is injected via line  60  into tubing  18  with the return connection on line  61  connected to the zone I casing segment ( 22 A). Electrical connection from tubing  18  to zone II casing segment  22 B is achieved in this embodiment through conductive packer  71 . 
     Communication with and power transmission to device  28  are achieved by direct connection of downhole device  28 . Device  28  and the casing segments  22 B and  22 C are connected in series, with independent connections via leads  28 A and  28 B on either side of gap  110  to casing segments  22 B and  22 C, respectively. Current from casing segment  22 B will flow through device  28  on lead  28 A to casing segment  22 C on lead  28 B. The series connection is as illustrated in FIG. 5B, discussed supra. 
     The injected current will flow along illustrative current lines  12  in tubing  18  through conductive packer  71  to zone II casing segment  22 B, through device  28  to zone III casing segment  22 C, leaking into annulus  40  via bottom electrode  72  and seeking a return path to zone I casing segment  22 A through top (return) electrode  70 . 
     The embodiment of FIG. 7 illustrates implementation of the present invention across two conductive conduits of varying diameter. 
     For illustrative purposes, an upper conduit section comprising a casing string  22  with an insulative layer  30 , is connected electrically to a lower conduit section comprising smaller diameter production tubing  221  with an insulative layer  301 . Insulative layers  30  and  301  form an insulated region A. Note that while it may be desirable to implement layers  30  and  301  as one continuous layer, a minimal break B between the layers  30  and  301  is acceptable because leakage through this exposed area would be negligible and not appreciably affect overall efficiency or operation of the present invention. Casing/casing and tubing/tubing conduit combinations are also possible as will be understood by one of skill in the art. 
     Operation of this embodiment is similar to that of the FIG. 4 embodiment where current is injected via direct coupling on line  60  and downhole device  28  is inductively coupled to the conduit via toroid  26 . As in FIG. 4, injection (i.e., connection of line  60 ) and toroid  26  must be disposed within insulated region A so as to inject a current which is confined to flow in the conduit within region A to inductively couple to toroid  26  also placed within region A. 
     The embodiment of FIG. 8 illustrates the utility of the present invention in a lateral (or “side-track”) well. 
     As discussed with regard to FIG. 7, implementation can be across conductive conduits of varying diameter. The illustrative embodiment of FIG. 8 shows an upper conduit section comprising a casing string  22  with an insulative layer  30  connected electrically to a lower conduit section comprising smaller diameter production tubing  221  with an insulative layer  301  (as in FIG.  7 ), and casing  222  and insulative layer  302  of a lateral well  2 . Insulative layers  30 ,  301  and  302  form insulated region A as shown. Note that, as in FIG. 7, while it may be desirable to have layers  30 ,  301  and  302  be continuous, small breaks B between the layers is acceptable because leakage through this exposed area would be minimal and not appreciably affect overall efficiency or operation of the present invention. Casing strings  22 ,  221  and  222  should be electrically connected. 
     Operation of this embodiment is similar to that of the FIG. 7 embodiment where current is injected via direct coupling on lines  60  and  61  (above and below gap  11 ) and downhole devices  28  and  28 ′ are inductively coupled to the conduit via toroids  26  and  26 ′. As in FIG. 7, injection (i.e., connection of line  60 ) must be within insulated region A so as to inject a current which will flow in the conduit within region A and likewise toroids  26  and  26 ′ must be placed within region A to capture the injected current. 
     Although not shown, addressable circuitry can be added to the encoder/decoder circuit  25  of surface equipment and  27 ,  27 ′ of downhole devices  28  and  28 ′ to effect independent communication and control of the individual downhole devices. 
     Additional various combinations including direct downhole device coupling and/or inductive injection coupling connections will also be understood. 
     FIG. 9 illustrates one embodiment of the present invention in which insulated casing and inductive coupling is used for downhole power and two-way signal transmission. 
     Toroid  23  is used for current injection where a current is induced in casing  22  within insulated region A. Toroid  23  is linked to surface by a cable  60 . Conduit gap  11  is used to form electrical zones I and II as previously discussed. 
     At the surface, electrical current is injected into toroid  23  via source  24  through cable  60 , thereby inducing a current in casing  22  (by known electro-magnetic principles). The induced casing current flows along illustrative current paths  12  through the casing  22  where, at the bottom of the casing, via bottom electrode  72 , the current leaks into the cement annulus  40  and flows through the annulus to the top (source and return) electrode  70 . 
     Measurement device  28  receives electrical power from a toroid  26  on the outside of the casing  22  via induction where the aforementioned current flowing through the casing (here induced by toroid  23  as described above) inductively generates a voltage in the toroid  26  that is used to power the sensor. The toroid  26  can be fitted and installed on segments of casing  22  during casing manufacture, as can various measurement devices intended for permanent installation. 
     The signal sensed by measurement device  28  is encoded into a second alternating voltage in the toroid  26  by downhole encoder circuit  27 , at a distinct frequency from that of the first injected current. This second voltage creates a second current in the casing  22 , which also flows along illustrative current lines  12  and is detected by a surface electronic detector  25  where it is recorded, stored or otherwise processed. 
     Although not shown, multiple measurement devices (of the same or different type) with encoding/decoding circuits, and multiple toroids may be placed at various points along the insulated casing. This allows a multitude of measurement devices to be distributed along the length of the well to accomplish diverse measurements. 
     The encoder/decoder circuit  27  of each measurement device may additionally be equipped with an addressable circuit that allows instructions to be sent to, and measurement signals received from, individually controllable measurement devices. 
     Illustrated in FIG. 10 is an alternative embodiment of the present invention where production tubing  18  is utilized as the conductive conduit and conventional (uninsulated) casing  22  is used as a return path for both communication with and power transmission to a downhole device  28 . 
     Operationally similar to the embodiments of FIGS. 5A and 6, the conduit is implemented as production tubing string  18  including tubing segments  18 A,  18 B and  18 C. Conduit gap  111  is placed within the tubing string to provide electrical isolation between tubing segments  18 A and  18 B. Second conduit gap  112  is located between tubing segments  18 B and  18 C to provide electrical zones I, II and III. The electrical zones result from the electrical “gap” between tubing segments  18 A and  18 B and  18 B and  18 C where tubing segment  18 A is electrically insulated from segment  18 B by gap  111  and  18 B electrically insulated from  18 C by gap  112 . Zone II tubing (i.e., tubing segment  18 B) is maintained in electrical isolation from casing  22  and is thus completely insulated electrically. This can be achieved in any of several known techniques such as providing an insulative layer around the tubing with the layer traversed or removed at connection to device  28 , or by using, for example non-conductive centralizers (not shown) or non-conductive fluid in the interior annulus (i.e., the space between the tubing and casing) (not shown). Electrical connection is established between tubing segment  18 C and casing  22  through conductive packer  71  for the current return path. 
     Surface equipment (including voltage source  24  and encoder/decoder  25 ) is connected to the tubing segment  18 B and casing  22  via a lines  60  and  61 , respectively. The current is injected via line  60  into tubing segment  18 B with a return connection on line  61  connected to casing  22 . 
     Direct connection of downhole device  28  to tubing  18  is used to communicate and provide power to device  28 . Device  28  and the tubing segments  18 B and  18 C are connected in series, with independent connections via leads  28 A and  28 B on either side of gap  112  to tubing segments  18 B and  18 C, respectively. Current from tubing segment  18 B will flow through device  28  to tubing segment  18 C. The series connection is similar to that illustrated in FIG.  18 B. 
     The injected current will flow along illustrative current lines  12  through tubing segment  18 B, through device  28  to tubing segment  18 C, through conductive packer  71  along a return path in casing  22 . 
     Direct downhole tubing connections such as discussed with respect to the embodiments of FIG. 10 can be achieved in any suitable manner to assure good (i.e., low loss, efficient) electrical contact. One known technique is via landing devices. The injection connection, via line  60  to tubing segment  18 B must be achieved downhole locally within zone II tubing. The return connection (via line  61  and casing  22 ), on the other hand, can be achieved downhole or alternatively near the surface without any diminished performance. 
     Illustrated in FIG. 11 is an alternative embodiment of the present invention as shown in FIG. 10 useful for connecting multiple downhole devices. Here production tubing  18  is utilized as the conductive conduit and conventional casing  22  are used for communication with a downhole device  28  within the well. 
     The conduit is implemented as a production tubing string  18  including tubing segments  18 A,  18 B and  18 C. Conduit gap  111  is placed within the tubing string to provide electrical isolation between tubing segments  18 A and  18 B. Second conduit gap  112  is disposed between tubing segments  18 B and  18 C to provide electric zones I, II and III. The electric zones result from the electrical “gap” between tubing segments  18 A and  18 B and  18 B and  18 C where tubing segment  18 A is electrically insulated from segment  18 B by gap  111  and  18 B electrically insulated from  18 C by gap  112  to completely insulate electrically tubing segment  18 B. 
     Surface equipment (including voltage source  24  and encoder/decoder  25 ) is connected to the tubing segment  18 B and casing  22  via a lines  60  and  61 , respectively. A voltage is applied via line  60  into casing segment  18 B with a return connection on line  61  connected to casing  22 . A differential voltage is thus established between tubing segment  18 B and casing  22 . 
     Direct connection of downhole device  28  is used to communicate with and provide power to device  28 . Device  28  is connected in parallel between the tubing segment  18 B and casing  22 . Current from tubing segment  18 B will flow through device  28  to casing  22 . 
     The current path will thus be along illustrative current lines  12  through tubing segment  18 B, through device  28  to a return path along casing  22 . 
     Direct downhole tubing connections such as discussed with respect to the embodiments of FIG. 11 can be achieved in any suitable manner to assure good (i.e., low loss, efficient) electrical contact. The voltage application connection, via line  60  to tubing segment  18 B must be achieved downhole locally within the zone II tubing (i.e., segment  18 B). The return connection (via line  61  and casing  22 ), on the other hand, can be achieved downhole or alternatively near the surface without any diminished performance. 
     As in FIG. 10, the zone II tubing (i.e., segment  18 B) should be kept electrically isolated from the casing string  22 . 
     FIG. 12A is an alternative embodiment of that of FIG. 10 useful for connection of multiple downhole devices. 
     This configuration allows for device-independent connection to maintain integrity of the series connection in case of fault at any one of the multiple devices. 
     The embodiment of FIG. 12A avoids direct connection of the downhole device to the tubing  18  by implementation of an intermediate transformer coil  128  across the two electrical zones on either side of the conduit gaps. Here several gaps are used to implement electrical zones I, II, III and IV, as shown. The coil  128  will allow current to flow freely around gap  112  through consecutive tubing segments  18 n+1 and  18 n+2 or  18 n+2 and  18 n+3, independent of the type of device deployed. A representative current path is illustrated in FIG. 12B via leads  128 A and  128 B. 
     Zone IV tubing is electrically connected to casing  22  via appropriate means such as conductive packer  71 . Where insulated tubing is used the insulative layer must be traversed or removed at conductive packer  71  to allow for electrical contact with,the casing. Conductive packer  71  will thus close the electrical circuit between tubing  18  and casing  22 . Zone II and III segments should remain in electrical isolation from casing  22 . 
     Downhole device  28  is then inductively coupled to coil  128  by a mating coil  228 . Addressable circuitry can be included in encoder decoder  27  to allow for independent control of individual devices. Although only 2 such downhole devices  28  are shown, any number can be deployed in this fashion, each in conjunction with a conduit gap as shown. 
     FIG. 13 is an alternative embodiment of the present invention as shown in FIG. 12A, illustrating application of the present invention across casing segments. 
     Principles of operation of the embodiment illustrated in FIG. 13 are similar to those described with respect to the embodiment of FIG. 12A as will be understood by one skilled in the art. 
     FIG. 14 depicts an illustrative embodiment of the conduit gap of the present invention. 
     For illustrative purposes, the various conduit gaps as discussed herein (with respect to FIGS. 4-13) are implemented as a threaded sleeve  32  of insulative material such as resin, ceramic or plastic, fitted between mating threaded conduit sections. In this illustration, the conduit is casing string with the threaded sleeve  32  fitted between adjoining threaded casing sections  22 n and  22 n+1. An outer insulative layer  30  is also provided in this embodiment external to the conduit to overlap the joined sections  22 n and  22 n+1 to prevent electrical connection between the two conduit sections via an external path, such as the surrounding cement or earth formation. 
     Where direct connection is utilized for current injection (such as illustrated in FIG. 14) and it is expected that conductive fluids (such as salt water) may be produced in the well, insulation on the interior of the conduit may be desirable to prevent a short circuit path between the contact points ( 60   a  and  61   a  in FIG. 14) through the conductive fluid. An inner insulative layer  303  around the inner circumference of the conduit (shown as casing  22  in the figure) is desirable. A minimum length l c  of layer  303  can be calculated based on factors including the distance d c  between contact points  60   a ,  61   a , the expected conductivity of the fluid and the level of current to be injected (i.e., the potential expected between points  60   a  and  61   a ). A maximum length is not critical because a longer (than minimum) insulative layer  303  will result in a gain in efficiency. 
     The manner in which electrical isolation of the conduit sections is achieved is not essential and the implementation shown in the illustrative embodiment is not intended to be restrictive. It is important only to achieve the desired result of electrically isolating two joined (i.e., consecutive) sections of conduit on either side of the gap from each other. 
     FIG. 15 shows an alternative embodiment of the present invention where the return circuit is provided by means of an additional conductive layer  140  applied to the outside of the insulating layer  130  on the conductive conduit, casing  122 , forming a three-layer conductor-insulator-conductor “sandwich”. The conductive layer  140  may be any conductive metal suitable for downhole use which applied to the outside of each insulated casing section before it is shipped to the wellsite; alternatively it could be in the form of a coating, paint or wrapping applied at the wellsite. 
     As shown in the drawing, insulative layer  130  is formed with an “overhanging” section  130   a  which will effect the conduit gap of the present invention. 
     The inner and outer conductors are electrically connected at some point during the run of the well so that current injected at the surface by source  24  via lines  60  and  61 , through encoder/decoder  25 , has a closed path within which to flow along illustrative current line  12 . In this embodiment, the connection between inner and outer conductors is accomplished at the bottom of the well by shunt  150 . A toroid  126  is disposed in the insulating layer  130 , i.e., “sandwiched” between the inner conductive casing  122  and the outer conductive layer  140 . 
     As in the earlier embodiments such as FIG. 4, measurement device  28  is installed on the casing  122  along with encoder/decoder  27 . Device  28  receives electrical power from toroid  126  where the current flowing through the casing  122  inductively generates a voltage in the toroid that is used to power the sensor. The device is connected to the toroid  126  via a lead through feed through nonconductive seal  160 . 
     The signal sensed by measurement device  28  is encoded into a second alternating current in the toroid  126 , at a frequency distinct from that of the current injected at the surface, thus creating a second current in casing  122  and conductive layer  140 , which is decoded by surface electronic encoder/decoder  25  and recorded or otherwise processed. 
     FIG. 16 illustrates another which utilizes direct downhole coupling. Like the embodiment of FIG. 15, a three-layer “sandwich”, comprising conductive casing  122 , insulating layer  130  and a second conductive layer  140 , is used. 
     The two conductive elements  122  and  140  are insulated from each other by extending insulating layer  130  beyond the length of conductive casing  122  and into region  180 , effecting a first conduit gap. As for the embodiment of FIG. 15, an “overhanging” section  130   a  effects a second conduit gap. 
     An electrical power source  24 , typically at surface and equipped with encoder/decoder  25 , establishes a voltage potential across the two conductive elements  140  and  122  via lines  60  and  61 . At various points along the well, measurement devices  28  measuring properties either inside or outside the well are connected across the two conductive elements as shown where insulating feed throughs  160  insulate and seal the area of the casing  122  through which a connection between measuring device  28  and the outer conductive layer  140  is made. The measurement devices  28  can be fitted and installed on segments of three-layer casing during casing manufacture to assure a reliable connection to the two conductive elements. Current flow will be through device  28  from casing  122  to outer conductive layer  140 . 
     The principle of operation of the alternative embodiment illustrated in FIG. 17 is similar to that of the embodiment illustrated in FIG. 16, with the conductive outer layer ( 140  of FIG. 16) replaced by an annulus of conductive cement  40 . The conductive casing  122  is covered with an insulating layer  130  which is surrounded by conductive cement annulus  40 . The two conductive elements (casing  122  and cement annulus  40 ) are insulated from each other, by extending insulating layer  130  beyond the length of conductive casing  122  and into region  180  forming a first conduit gap and “overhanging” section  130   a  effecting a second conduit gap. 
     At the surface, a voltage generator  24 , through encoder/decoder  25 , electrically connected to the casing  122  and cement annulus  40  (by electrode  266 ) via lines  60  and  61 , applies an electric potential across the casing  122  and the conductive cement  40 . At various points along the well, measurement devices  28  are placed to measure physical properties either inside or outside the casing. Such devices derive their electrical input power from the potential difference between the casing  122  and the conductive cement  40  in a manner similar to that of the FIG. 16 embodiment. In particular, the device  28  would have one power cable attached to the casing  122 , and the other would pass via an insulating feed through  160  to an electrode  267  situated in the conductive cement  40 . Current flow will be through device  28  from casing  122  to electrodes  267 , through conductive cement  40  to electrode  266  as shown by illustrative current lines  12 . 
     Electrodes  266  and  267  are illustrated as outer conductive layers or bands on limited segments of three-layer casing. These electrodes could also be implemented as mechanically separate electrodes disposed within the cement. However, compared to separate electrodes, implementation of the electrodes as shown in FIG. 17 as a section or band of casing would offer the advantage of increased surface area through which currents flow to power the measurement device(s). 
     In the illustrative embodiments described with respect to FIGS. 15-17, alternative methods of effecting the conduit gap can also be arranged as will be understood by one skilled in the art. 
     The present invention has been illustrated and described with respect to specific embodiments thereof. It is to be understood, however, that the above-described embodiments are merely illustrative of the principles of the invention and are not intended to be exclusive embodiments. 
     Alternative embodiments capturing variations in the embodiments disclosed herein can be implemented to achieve the benefits of the present invention. 
     It should further be understood that the foregoing and many various modifications, omissions and additions may be devised by one skilled in the art without departing from the spirit and scope of the invention.