MXPA02008508A

MXPA02008508A - Tracer injection in a production well.

Info

Publication number: MXPA02008508A
Application number: MXPA02008508A
Authority: MX
Inventors: Robert Rex Burnett
Original assignee: Shell Int Research
Priority date: 2000-03-02
Filing date: 2001-03-02
Publication date: 2003-01-28
Also published as: RU2002126211A; WO2001065053A1; BR0108888A; EP1259700B1; DE60128446D1; AU2001243391B2; BR0108888B1; NO20024137D0; CA2402163A1; DE60128446T2; NO326367B1; CA2402163C; NO20024137L; RU2263783C2; EP1259700A1; AU4339101A; OA13129A

Abstract

A petroleum well (20) comprises a well casing (30), a production tubing (40), a source of time varying current (68), a downhole tracer injection device (60), and a downhole induction choke (90). The casing (30) extends within a wellbore of the well (20). The tubing (40) extends within the casing (30). The current source (68) is located at the surface. The current source (68) is electrically connected to, and adapted to output a time varying current into, the tubing (40) and or the casing (30), which act as electrical conductors for providing downhole power and or communications to the injection device (60). The injection device (60) comprises a communications and control module (80), a tracer material reservoir (82), and an electrically controllable tracer injector (84). The communications and control module (80) is electrically connected to the tubing (40) and or the casing (30). The downhole induction choke (90) is located about a portion of the tubing (40) and or the casing (30). The induction choke (90) is adapted to route part of the electrical current through the communications and control module (80) by creating a voltage potential between one side of the induction choke (90) and another side of the induction choke (90). The communications and control module (80) is electrically connected across the voltage potential. The well (20) can further comprise a sensor (108) or a sensor device (140) located upstream of the injection device (60) and being adapted to detect the tracer material injected into the well by the injection device. The sensor device (140) may also be downhole, and may comprise a modem (146) to send data to the surface via the tubing (40) and or casing (30).

Description

- INJECTION OF A TRACTOR IN AN EXTRACTION WELL FIELD OF THE INVENTION The present invention relates to an oil well for the extraction of petroleum products. In one aspect, the present invention relates to systems and methods for monitoring fluid flow during oil extraction by controllably injecting tracer materials into at least one fluid flow stream with at least one injection system. of an electrically controllable downhole tracker from an oil well. DESCRIPTION OF THE RELATED ART Controlled injection of materials into oil wells (ie oil and gas wells) is an established practice often used to increase recovery or to analyze extraction conditions. It is useful to differentiate between types of injection, based on the quantities of materials that will be injected. Large volumes of injected materials are injected into the formations to displace formation fluids into the extraction wells. The most common example is water injection. In a less extreme case, the materials are introduced to the bottom of the well to carry out the treatment inside the well. Examples of these treatments include: REF. : 141672 (1) foaming agents to improve efficiency or artificial lift; (2) paraffin solvents to prevent the deposition of solids in the tubing; and (3) surfactant to improve the flow characteristics of the extracted fluid. These types of treatment involve modification of the well fluids themselves. Minor quantities are needed, although these types of injection are usually supplied by additional tubing directed to the bottom of the pool from the surface. Other additional applications require that they inject even smaller amounts of materials such as: (1) corrosion inhibitors to prevent or reduce the corrosion of the extraction equipment; (2) substances that impede fouling to prevent or reduce the formation of scaling of extraction equipment; and (3) material tracker to monitor the flow characteristics of the various sections of the well. In these cases, the quantities needed are small enough so that the materials can be supplied from a reservoir located at the bottom of the well, avoiding the need to place a supply tubing to the bottom of the well, from the surface . However, a successful application of techniques that require controlled injection from a downhole reservoir requires that a means be provided to provide energy and communicate with the downhole injection equipment. In existing practice, this requires the use of electrical cables that are available from the - surface to the injection modules deep in the well. Such cables are expensive and are not completely reliable, and as a result are considered undesirable in current extraction practice. The use of trackers to identify materials and track their flow is a technique established in other industries, and the development of tracking materials and detectors has advanced to the point where materials can be detected in dilutions below 10"10, and are Millions of individually identifiable markers are available A leading representative provider of such materials in Isotag LLC detection equipment from Houston, Texas The use of tracers to determine flow patterns has been applied in a wide variety of research fields, for example in the Observation of the biological circulation system in animals and plants has also been provided as a commercial service in the oil extraction industry, for example as a means to analyze injection profiles, however, the use of trackers for production in the oil fields is the exception, since there are methods that require the serration inside the drilled well of special equipment equipped with energy and controlled using hydraulic line cables from the surface to the deep in the well. All references mentioned herein are incorporated by reference in their maximum length permissible by law. To the extent that a reference is not fully incorporated herein, it is incorporated as a reference for background purposes and is indicative of the knowledge of a person ordinarily skilled in the art. SUMMARY OF THE INVENTION The problems and needs set forth in the above are solved and largely satisfied by the present invention. In accordance with one aspect of the present invention, a tracer injection system is provided for use in a well. The tracer injection system comprises a current impedance device and a downhole electrically controllable tracer injection device. The current impedance device is generally configured for concentric placement around a portion of a well pipe structure so that when electric current is transmitted by varying in time through and along the portion of the pipe structure, it is formed a voltage potential between one side of the current impedance device and the other side of the current impedance device. The downhole electrically controllable tracer injection device is adapted to be electrically connected to the pipe structure through the voltage potential that is formed by the device and current impedance, adapted to be energized by the current - electrical, and adapted to expel a tracer material into the well, in response to an electrical signal. In accordance with another aspect of the present invention, an oil well is provided for extracting petroleum products. The oil well comprises a pipe structure, a current source that varies with respect to time, an induction regulator, an electrically controllable tracer injection device and an electric return. The pipe structure comprises a first portion, a second portion and an electrically conductive portion extending within and between the first and second portions. The first and second portions are separated distally from each other along the pipe structure. The current source that varies with respect to time is electrically connected to the electrically conductive portion of the pipe structure in the first portion. In the induction regulator, it is located around a portion of the electrically conductive portion of the pipe structure in the second portion. The electrically controllable tracer injection device comprises two device terminals, and is located in the second portion. The electrical return is electrically connected between the electrically conductive portion of the pipe structure and the second portion of the current source. The first of the device terminals is electrically connected to an electrically conductive portion of the pipe structure over one side of induction regulator source. The second terminal of the device is electrically connected to the electrically conductive portion of the pipe structure on an electrical return side of the induction regulator or the electric return. According to a further aspect of the present invention, a well is provided comprising a pipe structure, a current source that varies with respect to time, an induction regulator, a sensing device and an electrical return. The pipe structure comprises a first portion, a second portion and an electrically conductive portion extending within and between the first and second portions. The first and second portions are separated distally from each other along the pipe structure. The current source that varies with respect to time is electrically connected to the electrically conductive portion of the pipe structure in the first portion. The induction regulator is located around a portion of the electrically conductive portion of the pipe structure in the second portion. The detector device comprises two device terminals and a detector. The detector device is located in the second portion, and the detector is adapted to detect a tracer material. The electrical return is electrically connected between the electrically conductive portion of the pipe structure, and the second portion, and a current source. The first of the terminals of - The device is electrically connected to the electrically conductive portion of the pipe structure on a source side of an induction regulator. The second of the device terminals is electrically connected to the electrically conductive portion of the pipe structure on an electrical return side of the induction regulator or the electric return. According to a further aspect of the present invention, an oil well is provided for extracting petroleum products. The oil well comprises a well casing, an extraction tubing, a current source that varies with time, a downhole tracer injection device, and a downhole induction regulator. The well liner extends into the well borehole. Extraction tubing extends into the liner. The source of current that varies with respect to the time it is located on the surface. The current source is electrically connected to, and adapted to, the output of a current that varies with respect to time inside the tubing or casing. The downhole tracker injection device comprises a communications and control module, a deposit of tracer material and an electrically controllable tracer injector. The communications and control module is electrically connected to the casing or casing. The tracer injector is - electrically connects to the communications and control module. The tracer material deposit is in fluid communication with the tracer injector. The downhole induction regulator is located around a portion of the tubing or casing. The induction regulator is adapted to direct part of the electrical current through the communications and control module to create a voltage potential between one side of the induction regulator and another side of the induction regulator, where the communication and control module it is electrically connected through the voltage potential. According to a further aspect of the present invention, a method is provided for extracting petroleum products from an oil well. The method comprises the steps of: (i) providing a pipe structure that extends into a well bore hole; (ii) providing a downhole tracker injection system for the well, comprising an induction regulator and an electrically controllable tracer injection device, the induction regulator is located downhole around the pipe structure so that when electric current is transmitted that varies with respect to time through the pipe structure, a voltage potential is formed between one side of the induction regulator and another side of the induction regulator the injection device of electrically controllable tracer is located at the bottom of the well, the The injection device is electrically connected to the pipe structure through the voltage potential that is formed by the induction regulator so that the injection device can be energized by the electric current, and the injection device is adapted to eject a tracer material in response to an electrical signal; and (iii) controllably injecting the tracer material into the downhole flow stream into the well with the tracer injection device during extraction. The method may further comprise the steps of: (iv) providing a downhole detector device, within the well, which is electrically connected to the pipe structure and which can be energized by the electric current; (v) monitoring the flow stream in the downstream position of the tracer injection device; (vi) detect the tracer material within the flow stream with the detector device; and (vii) act to alter the flow stream when this is desirable to meet the treatment or recovery objectives. In accordance with a further aspect of the present invention, a method for injecting fluids into a reservoir is provided. The method comprises the steps of: (i) providing a pipe structure that extends into a well bore hole; (ii) provide a downhole detector system for the well, comprising an induction regulator and a device detector, the induction plug is located at the bottom of the well around the pipe structure so that when electric current is transmitted that varies with respect to time, through the pipe structure, a voltage potential is formed between a side of the inductive shutter and another side of the injection shutter, the detector device is located in the bottom of the well, the detector device is electrically connected to the pipe structure through the voltage potential that forms by the induction plug in a way that the detector device can be provided with power by the electric current, and the detector device comprises a detector adapted to detect a tracer material; (iii) detecting the tracer material within a well flow stream with the sensing device during the fluid injection operation. The method may further comprise the steps of: (iv) providing a tracer injection device for the well at the surface; and (v) injecting the tracer material into the flow stream advancing into the well with the tracer injection device. BRIEF DESCRIPTION OF THE DRAWINGS Other objects and advantages of the invention will become apparent upon reading the following detailed description and with reference to the accompanying drawings, in which: Figure 1 is a schematic showing an oil extraction well, according to a preferred embodiment of the present invention; Figure 2A is a schematic of an upper portion of an oil well, in accordance with another preferred embodiment of the present invention; Figure 2B is a schematic of an upper portion of an oil well, in accordance with another additional preferred embodiment of the present invention; Figure 3 is an enlarged view of a downhole portion of the well shown in Figure 1; Figure 4 is a simplified electrical diagram of the electrical circuit that is formed by the well of the figure 1; Figures 5A to 5D are schematics of various tracker injectors and tracer material storage embodiments for an electrically controllable tracer injection device, which is downhole in accordance with the present invention; Figure 6 is a diagram of a detector device in an oil well, according to the present invention; The 7A to 7E are uniform input flow schemes and injection profiles for various well configurations; Figure 8 is a graph illustrating fluid flow lines in a circular tube with laminar flow in the case where the fluids enter the tube uniformly in its wall along the length of the tube; Figures 9A to 9J are simplified schemes illustrating examples of various configurations for the tracker injection device and positioning of the detector device within various well configurations; Figure 10 are normalized graphs of the arrival time on the ordinate axis as a function of the normalized depth on the abscissa axis for the simulation of the inflow using 100 input flow zones; Figure 11 are standardized arrival time graphs on the ordinate axis, as a function of the normalized depth on the abscissa axis for a simulation of the inflow using 1000 input flow zones; Figure 12 defines the injectivity profile of an illustrative injection well by plotting the injectivity profile on the ordinate axis, as a function of the depth, on the abscissa axis; Figure 13 shows the transit time of the tracker per unit length of the illustrative injection well defined in figure 12, when showing the transit time in the axis of the ordinates, as a function of the depth in the axis of the abscissa; - Figure 14 shows the time of arrival of the tracker in the illustrative injection well defined in figure 12 when showing the arrival time on the axis of the ordinates, as a function of the depth on the abscissa axis; Figure 15 compares the calculated and actual injection speeds as a function of the depth in the illustrative injection well defined in Figure 12 when plotting the injection velocity on the ordinate axis, as a function of the depth in the abscissa axis; Figure 16 defines four illustrative cases of production wells by plotting the cumulative input flow on the ordinate axis, as a function of the depth on the abscissa axis; Figure 17 shows the normalized arrival time of a tracker injected into the axis of the ordinates, as a function of the depth for the four illustrative cases of extraction wells defined in Figure 16; Figure 18 shows the normalized arrival times of an injected tracer, in relation to a case of uniform injection velocity in the axis of the ordinates, as a function of the depth for the four illustrative cases of the production wells that are defined in figure 16; Figure 19 shows the relative concentration of the tracker pulses on the axis of the ordinates, as a function of the arrival time on the abscissa axis for the case of uniform inflow with respect to an extraction interval; FIG. 20 graphs the relative concentration of the tracker pulses on the ordinate axis, as a function of the arrival time on the abscissa axis for an illustrative case of non-uniform input flow over an extraction interval; Figure 21 shows the relative concentration of the re-tracker pulses on the axis of the ordinates as a function of the time of arrival on the abscissa axis for a second illustrative case of non-uniform inflow over an extraction interval; Figure 22 shows the relative concentration of the tracker pulses, on the axis of the ordinates, as a function of the arrival time on the abscissa axis for a third illustrative case of non-uniform inflow, over an extraction interval; Figure 23 shows the cumulative pressure drop along the tubing on the ordinate axis, as a function of the distance along a horizontal well on the abscissa axis for several illustrative cases of differences between the pressure of the reservoir and pressure at the bottom of the well, in the wells of horizontal termination; Y Figure 24 graphs the relative input flow rates per unit length on the ordinate axis, as a function of the distance along a horizontal well on the abscissa axis for various illustrative cases of pressure differences of the reservoir and the pressure at the bottom of the well, in a well of horizontal termination. DETAILED DESCRIPTION OF THE INVENTION Referring now to the drawings, in which similar reference numerals are used herein to designate similar elements throughout the various views, the preferred embodiments of the present invention are further illustrated and described. The figures are not necessarily drawn to scale, and in some cases the drawings have been exaggerated or simplified for illustrative purposes only. A person ordinarily skilled in the art will appreciate the many possible applications and variations of the present invention based on the following examples of the possible embodiments of the present invention, and likewise based on those modalities illustrated and discussed in the related applications, which are incorporated herein by reference to the maximum extent permitted by law. As used in the present application, a "pipe structure" can be a single pipe, a pipe chain, a well liner, a pipe rod, - pumping, a series of tubes, rods, rails, trusses, grids, supports, a branch or side extension of a well, a network of interconnected pipes or other similar structures known to those ordinarily skilled in the art. A preferred embodiment makes use of the invention in the context of an oil well where the pipe structure comprises a tube or chain of tubular, metallic, electrically conductive tubes, but the invention is not limited in this way. For the present invention, at least a portion of the pipe structure needs to be electrically conductive, for example an electrically conductive portion can be the entire pipe structure (e.g., steel pipes, copper pipes) or an electrically conductive portion. conductive extending, longitudinally combined with a non-conductive portion extending longitudinally. In other words, an electrically conductive pipe structure is one that provides an electrical conduction path from a first portion where a power source is electrically connected to a second portion where a device or an electrical return is electrically connected. The pipe structure will typically be a conventional round metal tubing, but the cross section geometry of the pipe structure, or any portion thereof, may vary in shape (eg, round, rectangular, square or oval) and size (eg length, diameter, wall thickness) throughout of any portion of the pipe structure. Therefore, a pipe structure can have an electrically conductive portion extending from a first portion of the pipe structure, to a second portion of the pipe structure, wherein the first portion is spaced distally from the second portion of the pipe structure. along the pipe structure. The terms "first portion" and "second portion", as used herein, are each generally defined to highlight a portion, section or region of a pipe structure that may or may not extend along the pipe structure , and which can be located at any chosen location along the pipe structure, and which may or may not encompass the nearest ends of the pipe structure. The term "modem" is used herein to refer generically to any communication device that transmits or receives electrical communication signals by means of an electrical conductor (e.g. metal). Therefore, the term "modem" as used herein, is not limited to the acronym for a modulator (device that converts a voice or data signals into a form that can be transmitted) / demodulator (a device that retrieves a original signal after it has been modulated at a high carrier frequency). In addition, the term "modem", as used herein, is not limited to conventional computer modem equipment that - convert digital signal into analog signals and vice versa (for example, to send digital data signals over the public analogue switched telephone network). For example, if a detector transmits measurements in an analog format, then such measurements may only need to be modulated (for example broadcast spectrum modulation) and transmitted - therefore analog / digital conversion is not necessary. As another example, a relay / slave modem or communication device may only be needed to identify, filter, amplify or retransmit a received signal. 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 can be used to regulate the flow of the rising gas in a pipeline chain. a well. The internal or external works of the valves "can vary greatly and in the present application, it is not necessary to limit the valves described to any particular configuration, as long as the valve functions to regulate the flow. of flow regulation mechanisms include, but are not limited to, ball valve configurations, needle valve configurations, gate valve configurations and cage valve configurations.

The installation methods for the valves discussed in the present application can vary widely. 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 a control signal electrical (for example, a signal from a computer on the surface or from an electronic controller module at the bottom of the well). The mechanism that actually moves the position of the valve may include, but is not limited to: an electric motor; a servo-electric system; an electric solenoid; an electric switch; a hydraulic actuator controlled by at least one servo-electric system, an electric motor, an electric switch, an electric solenoid or combinations thereof; a pneumatic actuator controlled by at least one servo-electric system, - an electric motor, an electric switch, an electric solenoid or combinations thereof; or a spring-biased device in combination with at least one servo-electric system, an electric motor, an electric switch, an electric solenoid or combinations thereof. An "electrically controllable valve" may or may not include a position feedback detector to provide a feedback signal corresponding to the actual position of the valve.

The term "detector", as used herein, refers to any device that detects, determines, monitors, registers or otherwise perceives the absolute value of a change in a physical quantity. A detector, as described herein, can be used to measure physical quantities that include, but are not limited to: temperature, pressure (absolute and differential), flow rate or flow rate, seismic data, acoustic data, level of pH, salinity levels, valve positions, volume or almost any other physical data. A detector, as described herein may also be used to detect the presence or concentration of a tracer material within a flow stream. The phrase "on the surface", as used herein, refers to a position that is above approximately a depth of approximately 15.2 m (50 feet) inside the earth. In other words, the phrase "on the surface" does not necessarily mean placed on the floor or at the floor level, but is used more broadly in the present to refer to a position that is often easily or conveniently accessible in the head of the well or upper part of it where people can work. For example, "on the surface" can be on a table on a work shelf that is located on the ground on an extraction platform, or it can be on the ocean floor or at the bottom of a lake, or it can be on the oil extraction platform in the open sea, or - - It can be on the hundredth floor of a building. In addition, the term "surface" can be used herein as an adjective to designate a position of a component or region that is located "on the surface". For example, as used herein, a computer on the "surface" may be a computer that is located "on the surface". The term "bottom", as used herein, refers to a location or position below approximately 15.2 m (50 feet) deep within the earth. In other words, the term "background" is widely used herein to refer to a place that is often not easily or conveniently accessible from the top of the well where people may be working. For example, in an oil well, a "bottom" location is often in or near the oil extraction zone below the surface, regardless of whether the production zone has vertical, horizontal, lateral, or vertical access. in any other angle between them. In addition, the term "background" is used herein as an adjective describing the location of a component or region. For example, a device in the "bottom" in a well will be a device that is located in "the bottom" as opposed to one that is located "on the surface". As used in the present application, "wireless" means the absence of a conventional insulated wired conductor, for example, extending from a - device in the background, to the surface. Using the tubing or casing as a conductor, it is considered "wireless". Similarly, according to the conventional terminology in oil field practice, the descriptions "upper", "lower", "at the top of the hole" and "at the bottom of the hole" refer to and relate to the distance along the whole depth of the well from the surface, which, in the deviated or horizontal wells, may or may not agree with the vertical elevation measured with respect to research data. Figure 1 is a diagram showing a well 20 for extracting oil, according to one. 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 that extends into the drill hole and through reservoir 32, and an extraction pipe 40 that extends into the well casing to transport fluids from the bottom of the well to the surface during extraction. Therefore, the oil extraction well 20 shown in Figure 1 is similar to those that exist in practice in the construction of wells, but with the incorporation of the present invention. The vertical section 22 in this embodiment incorporates a gas lift valve 42 and a top packing plug 44 to provide artificial lift for fluids within the tubing 40. However, in a - Alternatively, other ways of providing artificial lift can be incorporated to form other possible modalities (for example, rod pumping). In addition, the vertical portion 22 may further vary to form many other possible embodiments. For example, in an improved form, the vertical portion 22 may incorporate one or more electrically controllable gas lift valves, one or more additional induction regulators, and one or more controllable packing seals comprising electrically controllable seal valves, as described further in the related applications. The side section 26 of the well 20 extends through the oil extraction zone 48 (eg, the oil zone) of the reservoir 32. The casing 30 in the side section 26 is drilled in the extraction zone 48 to allow the fluids from the extraction zone 48 flow into the interior of the coating. Figure 1 shows only a side section 26, but there may be many side branches of the well 20. The well configuration will typically depend, at least in part, on the distribution of the extraction zones for a given reservoir. Part of the tubing 40 extends into the side section 26 and ends with a closed end 52 passing the extraction zone 48. The position of the tubing end 52 within the liner 30 is maintained by a side packing plug 54, which is an obturator conventional packaging. The tubing 40 has a section 56 perforated in the extraction zone 48 for fluid intake from the extraction zone 48. In other embodiments (not shown) the tubing 40 may continue to exceed the extraction zone 48 (eg, to other extraction zones), or the tubing 40 may end with an open end for fluid intake. An electrically controllable downhole tracker injection device 60 is connected in line with the tubing 40 within the side section 26 and forms part of the extraction tubing assembly. The injection device is located upstream of the extraction zone 48 near the vertical section for ease of placement. However, in other embodiments, the injection device 60 may additionally be placed within a side section. An advantage of placing the injection device 6D close to the pipe inlet 56 in the extraction zone 48 is that it is a desirable position to inject a tracer material. But when the injection device is located remote in relation to the pipe intake 56, as shown in Figure 1, a tracer material can be injected into the pipe inlet 56 in the extraction zone 48 using a pipe 70 of nozzle extension. The nozzle extension tube 70 in this manner provides a way of injecting a tracer material into a flow stream in a position remote from the device 60 of injection. By ejecting a tracer material in a position remote from (for example, upstream of) the injection device 60, by means of the nozzle extension tube 70, a detector adapted to detect tracer material is allowed to be located on or within the device. 60 of injection. (Such detector is number 108, as shown in Figure 3). In other possible embodiments, the injection device 60 can be adapted to controllably inject a tracer material in a position outside the tubing 40 (eg, directly within the extraction zone 48 or within an annular space 62, within the coating 30). ). Therefore, an electrically controllable downhole tracker injection device 60 can be placed in any downhole position within a well where it is needed. An electrical circuit is formed using various components of the well 20. The energy for the electrical components of the injection device 60 is provided from the surface using the tubing 40 and the coating 30, as electrical conductors. Therefore, in a preferred embodiment, the tubing 40 acts as a pipe structure and the liner 30 acts as an electrical return to form an electrical circuit in the well 20. In addition, the tubing 40 and the liner 30 are used as conductors electrical devices for communication of signals between the surface (for example a computer system 64 on the surface), and electrical components at the bottom of the well inside the electrically controllable downhole tracker injection device 60. In Figure 1, a computer system 64 on the surface comprises a master modem 66 and a current source 68 that varies with respect to time. But, as will be clear to a person ordinarily skilled in the art, equipment on the surface may vary. A first computer terminal 71 of the surface computer system 64 is electrically connected to the casing 40 on the surface, and imparts electric current that varies with respect to the time inside the casing 40 when the power or communications with the devices at the bottom of Well are necessary. The current source 68 provides the electric current, which carries energy and communication signals to the bottom of the well. The electric current that varies with respect to time is preferably alternating current (AC), but it can also be direct current (DC). The communication signals can be generated by the master modem 66 and can be embedded within the current produced by the source 68. Preferably, the communication signal is a broadcast spectrum signal, but other forms of modulation or modulation can be used as alternatives. of distortion elimination. A first induction regulator 74 is located around the tubing in the vertical section 22 below the position where the lateral section 26 extends from the vertical section. A second induction regulator 90 is located around the tubing 40 within the side section 26, next to the injection device 60. The induction regulators 74 and 90 comprise a ferromagnetic material and are found without power. Because the regulators 74 and 90 are located around the tubing 40, each regulator acts as a large inducer for AC in the well circuit that is formed by the tubing 40 and the liner 30. As described in greater detail in the applications related, regulators 74 and 90 operate based on their size (mass), geometry and magnetic properties. An insulated tubing gasket 76 is incorporated into the well head to electrically isolate the tubing 40 from the liner 30. The first computer terminal 71 from the current source 68 passes through an insulated seal 77 in the hanger. electrically connects to the tubing 40 below the insulated tubing joint 76. A second computer terminal 72 of the computer system 64 on the surface is electrically connected to the coating 30 on the surface. In this way, the insulators 79 of the pipe joint 76 prevent a short between the tubing 40 and the cover 30 on the surface. In an alternative (or additionally) to the insulated tubing joint 76, a third induction regulator 176 (see Fig. 2A) may be placed around the tubing 40 above the electrical connection position for the first - - terminal 71 of the computer to the tubing, or to the hanger 88 which may be an insulated hanger 276 (see Fig. 2B) having insulators 277 for electrically insulating the casing 40 from the casing 30. The side packing plug 54 at the end 52 of tubing within the side section 26 provides an electrical connection between the tubing 40 and the downhole liner 30 surpassing the second regulator 90. A lower packing plug 78 in the vertical section 22, which is also a packing plug conventional, provides an electrical connection between the tubing 40 and the liner 30 in the downhole, below the first induction regulator 74. The upper packing plug 44 of the vertical section 22 has an electrical insulator 79 to prevent an electrical short between the tubing 40 and the liner 30 in the upper packing seal. further, various centralizers (not shown) having electrical insulators to prevent shorts between the tubing 40 and the liner 30 can be incorporated as needed through the well 20. Such electrical insulation of the upper packing plug 44 or a centralizer can be obtained from various obvious ways for a person usually skilled in the art. The packing plugs 44 and 78, upper and lower, provide hydraulic isolation between the main drilling well of the vertical section 22 and the lateral drilling well of the lateral section 26.

Figure 3 is an enlarged view showing a portion of the side section 26 of Figure 1 with an electrically controllable downhole tracker injection device 60 therein. The injection device 60 comprises a communication and control module 80, a reservoir 82 of tracer material, an electrically controllable tracer injector 84, and a detector 108. Preferably, the components of a tracer injection device 60 at the bottom of the Well, electrically controllable, all are contained in a single capsule 86 of sealed, unique tubing, together as a module for ease of handling and installation, as well as to protect the components of the surrounding environment. However, in other embodiments of the present invention, the components of a downhole tracker injection device 60, electrically controllable, may be separate (ie, not inside the tubing capsule 86) or may be combine in other ways. A first device terminal 91, of the injection device 60 is electrically connected between the tubing 40 on a source side 94 of the second induction regulator 90 and the communication and control module 80. A second device terminal 92 of the injection device 60 is electrically connected between the tubing 40 on an electrical return side 96 of the second induction regulator 90 and the communication and control module 80. Although the side packing plug 54 provides an electrical connection between the tubing 40 on the electrical return side 96 of the second induction regulator 90 and the liner 30, the electrical connection between the tubing 40 and the liner 30 of the well can also be carried out in numerous ways, some of which can be see in related applications that include (but are not limited to): another packaging obturator (conventional or controllable); in driver centralizer; conductive fluid in the ring, between the tubing and the well casing; or any combination of these. Figure 4 is a simplified electrical schematic illustrating the electrical circuit that is formed in the well 20 of Figure 1. In operation, and with reference to both Figure 1 and Figure 4, energy or communications are imparted to the interior of the tubing 40 on the surface by means of a first computer terminal 71 below the insulated tubing joint 76. The current that varies with respect to time is prevented from flowing from the tubing 40 to the liner 30 by means of a hanger 88 due to the insulators 79 of the insulated tubing joint 76. However, the current that varies with respect to time flows freely along the tubing 40 until it meets the induction regulators 74 and 90. The first induction regulator 74 provides a large inductance which prevents most of the current from flowing through the tubing 40 in the first induction regulator. Similarly, the second induction regulator 90 provides a large inductance which prevents most of the current from flowing through the tubing 40 in the second induction regulator. A voltage potential is formed between the tubing 40 and the liner 30 due to the induction regulators 74 and 90. The voltage potential is also formed between the tubing 40 and the source side 94 of the second induction regulator 90 and the tubing 40 of the electrical return side 96 of the second induction regulator 90. Because the communications and control module 80 is electrically connected through the voltage potential, most of the current imparted to the tube 40 that has not been lost along the path is directed through the communications module 80 and control, which distributes or decodes the energy or communications for the injection device 60. After passing through the injection device 60, the current returns to the surface computer system 64 by means of a side packing plug 54 and the jacket 30. When the current is AC, the flow of the current just described will also be reversed through the well 20 a along the same path. Other alternative ways of developing an electrical circuit using a pipeline structure of a well and at least one induction regulator are described in related applications, many of which may be applied in conjunction with the present invention to provide power and communications to devices at the bottom of the well - provided with electrical energy and from other embodiments of the present invention. Referring to Figure 3 again, the communication and control module 80 comprises an individually addressable modem 100, power conditioning circuits 102, a control interface 104 and a detector interface 106. Because the modem 100 of the downhole injection device 60 is individually addressable, more than one device can be installed downhole and can be operated independently of each other. In Figure 3, the electrically controllable tracker injector 84 contacted to the communications and control module 80 and thus energy or communications is obtained from the surface computer system 64 via the communication and control module 80. The deposit -82 of tracer material is in fluid communication with the tracker injector 84. The reservoir 82 of tracer material is a self-contained reservoir that stores and supplies tracking materials for injection into the flow stream by the tracer injector 84. The reservoir 82 of tracer material of Figure 3 is not supplied by the supply line of tracer material (not shown) extending from the surface, but in other embodiments it may be so. Therefore, the size of the deposit 82 of the tracer material may vary based on the volume of materials tracker needed to inject into the well 20. The tracker 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 and receives motion instruction signals from the communication and control module 80. The nozzle extension tube 70 extends from the nozzle 114 to the interior 116 of the tubing in the tubing inlet 56 (further toward the upper end) and provides a fluid passage from the reservoir 82 of tracer material to the tubing interior 116. The screw mechanism 112 is mechanically coupled to the electric motor 110. The screw mechanism 112 is used to propel tracking materials out of the reservoir 82 and into the tubing interior 116, by means of the nozzle 114 and by means of the nozzle extension tube 70, in response to a rotational movement of the electric motor 110 . Preferably, the electric motor 110 is a stepper motor and thus provides injection of tracer material in increasing amounts. In operation, the fluid stream from the extraction zone 48 passes around the tracer injection device 60 as it flows through the tubing 40 to the surface. The instructions from the computer system 64 on the surface are transmitted downhole and are received by the modem 100 of the communication and control module 80. Within the device 60 of - Injection the instructions are decoded and passed from the modem 100 to the control interface 104. The control interface 104 then instructs the electric motor 110 to operate and inject the specified amount of tracer materials from the reservoir 82 into the fluid flow stream in the tubing 40. Therefore, the tracer injection device 60 injects the controllable the tracer material within the fluid stream flowing into the tubing 40, as needed or desired, in response to instructions from the surface computer system 64 via the communication and control module 80. The tracer injection device 60 of Figure 3 also comprises detectors 108. At least one of the detectors 108 is adapted to detect the presence or concentration of a tracer material within the flow stream passing through the tubing 40. The detectors 108 are electrically connected to the communication and control module 80 via the interface 106 of the detector. The tracer injection device 60 may also further comprise detectors for performing other measurements, such as the flow rate, temperature or pressure. The data of the detectors 108 are encoded within the communication and control module 80 and can be transmitted to the computer system 64 on the surface by the modem 100. Thus, during operation, when the tracking material is injected into the interior 116 of - piped upstream by the tracer injector 84 (via the nozzle extension tube 70), the detectors 108 detect the tracker as it passes within the flow stream. By measuring the arrival time (time from injection to detection) or the concentration of detected tracer, the characteristics of the flow stream can be determined, as further detailed in the following in this document. As will be apparent to a person ordinarily skilled in the art, the mechanical and electrical distribution as well as the configuration of the components within an electrically controllable tracer injection device 60 may vary while still performing the same function - providing electrically controllable tracer injection. at the bottom of the well. For example, the contents of a communications and control module 80 can be as simple as a wired connector terminal for distributing electrical connections from the tubing 40, or it can be very complex and comprise (but not limited to) a modem, a battery rechargeable, an energy transformer, a microprocessor, a memory storage device, a data acquisition card and a motion control card. Figures 5A to 5D illustrate some possible variations of the deposit 82 of tracer material and of the tracer injector 84 that can be incorporated in the present invention to constitute other modalities - possible. Figures 5A to 5D, the nozzle extension tube 70 is not incorporated. Therefore, the tracer injection devices shown in Figures 5A to 5D are adapted to be located in a position where the tracker injection is desired. However, a nozzle extension tube may also be incorporated within any of the embodiments shown in Figures 5A to 5D. In Figure 5A, the tracker injector 84 comprises a pressurized gas reservoir 118, a pressure regulator 120 and an electrically controllable valve 122, and a nozzle 114. The pressurized gas reservoir 118 is fluidly connected to the reservoir 82. by means of pressure regulator 120 and therefore supplies a generally constant gas pressure to the reservoir. The reservoir 82 of tracer material has a bag 124 therein that contains the tracer materials. The pressure regulator 120 regulates the passage of pressurized gas supplied from the pressurized gas reservoir 118 into the reservoir 82 but out of the bag 124. However, the pressure regulator 120 can be replaced with an electrically controllable valve. The pressurized gas exerts pressure on the bag 124 and therefore on the tracer materials therein. The electrically controllable valve 122 regulates and controls the passage of the tracking materials through the nozzle 114 and into the interior 116 of the tubing. Because the tracking materials - inside the bag 124 are pressurized by the reservoir gas 118 of pressurized gas, the tracer materials are forced out of the nozzle 114 when the electrically controllable valve 122 is opened. In Figure 5B, the scouring reservoir 82 is divided into two volumes, 126 and 128, by a bag 124, which acts as a spacer between the volumes 126 and 128. A first volume 126 within the bag 124 contains the tracer material, and the second volume 12 within the reservoir 82 of tracer material, but outside the bag, contains pressurized gas. Therefore, the reservoir 82 is preloaded and the pressurized gas exerts pressure on the tracer materials within the bag 124. The tracer injector 84 comprises an electrically controllable valve 12 and a nozzle 114. The electrically controllable valve 12 is electrically connected and s controlled by the communication and control module 80. The electrically controllable valve 122 regulates and controls the passage of the tracer materials through the tober 114 into the inner part 116 of the tubing. The tracking materials are forced out of the tober 114 due to the gas pressure when the electrically controllable valve 12 is opened. The embodiment shown in Figure 5C is similar to that of Figure 5B, but the pressure in the bag 12 is provided by a spring element 130. Also, in figure 5C, the bag may not be necessary if there is a sell mobile (for example a sealed piston) between the spring element 130 and the tracer materials within the reservoir 82. A person with ordinary skill in the art will see that there may be many variations in the mechanical design of the tracker injector 84 and in the use of a spring element "to provide pressure in the tracer materials In Figure 5D, the reservoir 82 of tracer material has a bag 124 containing a tracer material, the tracer injector 84 comprises a pump 134, a valve 136 of a Via a nozzle 114 and an electric motor 110. The pump 134 is driven by the electric motor 110, which is electrically connected and controlled by the communications and control module 80. The one way valve 136 prevents backflow into the interior of the pump 134 and the bag 124, the pump 134 drives the tracking materials out of the bag 124. Through the one-way valve 136, out of the nozzle 114 and ro of the inner part of 116 of the tubing. Therefore, the use of the tracer injector 84 of Figure 5D may be useful in the case where the reservoir 82 of tracer material arbitrarily conforms to maximize the volume of tracer materials that are held therein for a given configuration, to which the configuration of the tank does not depend on the configuration of the injector 84 tracker is simply.

- Thus, as illustrated in the examples in Figures 5A to 5D, there are many possible variations for the scouring tank 82 and the tracer injector 84. A person ordinarily skilled in the art will see that there may be many more variations to carry out the functions of storing the downhole tracking materials, in combination with the controllable injection of the tracking materials into the interior of the casing 116 in response to an electrical signal. Variations (not shown) in the tracer injector 84 may also include (but are not limited to): a venturi-type tube in the nozzle; pressure in the bag provided by a turbine device that extracts rotational energy from the fluid flow within the tubing; extraction of pressure from other regions of the directed formation via a tubing, any possible combination of the parts in Figures 5A to 5D, or any combination thereof. The tracer injection device 60 may not inject tracer materials into the tubing interior 116. In other words, a tracker injection device can be adapted to controllably inject tracking materials into the formation 32, within the cover 30, or directly into the extraction zone 48. In addition, a single tracker injection device 60 can be adapted to eject multiple tracking materials (i.e., identifiers or - different tracker characteristics), for example having multiple material tracking tanks 82 or multi-track multiple injectors 84. A single tracer injection device 60 can be adapted to inject tracer materials into a well in many places, for example, by having multiple nozzle extension tubes 70 that extend to multiple positions. The tracker injection device 60 may further comprise other components to form other possible embodiments of the present invention that include (but not limited to): other detectors, a modem, a microprocessor, a logic circuit, an electrically controllable tubing valve, multiple tracer material reservoirs (which may contain different tracer), multiple tracer injectors (which they can be used to eject multiple tracking materials in different places), or - any combination thereof. The injected tracer material can be solid, liquid, gaseous or mixture thereof. The injected tracer material can be a single component, multiple components or a complex formulation. In addition, there may be multiple controllable tracer injection devices for one or more side sections, each of which may be independently addressable, addressable in groups or uniformly addressable from the surface computer system 64. As an alternative to being controlled by the surface computer system 64, - the downhole electrically controllable injection device 60 can be controlled by electronic circuits in the same or by another device which is located at the bottom of the well. Likewise, the downhole electrically controllable injection device 60 can control or communicate with other devices downhole. In an improved form of an electrically controllable tracer injection device 60, it comprises at least one additional detector, each adapted to measure a physical quality as (but not limited to): absolute pressure, pressure differential, fluid density, fluid viscosity, transmission properties or acoustic reflection, temperature or chemical constitution. In addition, the tracker injection device 60 may not contain any detector (i.e., without the detector 108), and the detector 108 for detecting a tracer material may be located separately and away (e.g., downstream or on the surface), at relation to the tracker injection device 60. Figure 6 illustrates an example of a device 140 is a separate downhole detector having its own corresponding induction regulator 142 which is located proximate thereto for directing power or communications for the detector device. The detector device 140 comprises a detector 108, a communications and control module 144 and a modem 146. In this way, the data acquired by the detector device 140 can be transmitted to a - surface computer system or other downhole device using casing 40 or casing 30, as an electrical conductor. In another method of additional operation, the trackers can be generated downhole by the use of electric currents, thus eliminating the need for a downhole chemical deposit. This method offers the opportunity of a constant supply of tracer during the useful life of the well. For example, changes in the pH of a natural brine can be carried out by an electrolytic cell which decomposes the salts in gaseous chlorine or metal hydroxide. Usually, sodium chloride is decomposed into gaseous chlorine and metallic hydroxide. A pH detector can be used to detect such a pulse of water with a pH that is generated online or that is collected and released as a plug. Another potentially useful electrically driven chemical reaction is the generation of ozone such as that which is used in biological activity control devices in swimming pools and water supply systems. In another application, a solid material may be placed in the well and a flowing stream may be caused to enter the well by a controlled solution that is acquired by a controlled pulse of electrical energy. The dissolved material is preferably unique to the well's fluid environment, so detection is allowed to lower concentrations. An example of such a solid material is a metallic zinc element. The - commercially available analytical devices provide detection of many other compounds that can be electrically generated by those skilled in the art. Upon review of related applications, a person ordinarily skilled in the art will see that there may also be other downhole devices electrically controllable, as well as numerous induction regulators, additionally included in a well to constitute other possible embodiments of the present invention. Such other electrically controllable downhole devices include (but are not limited to): one or more controllable packing seals having shutter control valves, which can be electrically controlled, one or more electrically controllable gas lift valves; one or more modem devices, one or more detectors; a microprocessor; a logical circuit; one or more electrically controllable tubing valves for controlling flow from various side branches; and other electronic components, as needed. When used, many applications of the present invention will arise both in conventional wells and in future complex designs, for example, in vertical wells completed over extended intervals, the inlet flow profiles of the extraction wells are of interest in order to correct an irregular inflow and - this way allow the uniform suppression of all training. Similarly, flood operations at large interval terminations depend on obtaining uniform injection profiles in order to sweep the entire zone. Figures 7A and 7B schematically illustrate the uniform inflow and uniform injection flow profiles, respectively, for a vertical well. In wells with large horizontal terminations, the maintenance of uniform profiles depends less on the differences in the permeabilities of geological layers than on the pressure gradients along the wells. Pressure gradients tend to favor high extraction velocities near the well bifurcation (ie, the horizontal section closest to the vertical part of the well). Figures 7A and 7D schematically illustrate the uniform input and injection flow profiles, respectively, for a large horizontal termination. Another application is the use of trackers to differentiate extraction in wells with multiple side branches. In these wells it is important to understand which of the lateral branches produces excess water and which of the branches has already been depleted. Figure 7E schematically illustrates a uniform inlet flow profile for multiple side branches. Therefore, Figure 7A through 7E illustrate the desirable flow profiles for only some of the many possible well configurations, which greatly depend - measure of the natural distribution of the extraction zones in a given reservoir. The movement of fluids in an underground well can be monitored by injecting trackers in various positions and observing the arrival time and dilution of the fluids entering the well downstream of the point of injection of the tracer. As described in the foregoing, the trackers are injected in a flow stream from a storage tank 82 into an injection device 60. But alternatively, a tracker can be generated within the injection device 60 by electrical methods. The movement of a crawler tap injected into a well stream depends on the degree of mixing during its transport along the well. In the case of a simple flow in a tube, the velocity profile varies with the radial position, so that the fluids move a little faster in the center of the tube than in the walls. If the flow is in the laminar region (ie, low speeds), the shape of the parabolic velocity profile, and in the case of lack of slippage in the wall, a tracker will disperse over the length of the flow. In practice, because the walls of the tube are rough and the flow is fast, turbulent flow usually occurs. The turbulence mixes the fluids so that the trackers are transported more evenly and generally reflect the average flow velocity in the tube.

In extraction or injection wells completed with perforated or screened coatings, the fluid inlet flow occurs through the pipe wall into the flow stream along the wellbore. In this case, the flow of a fluid entering the well in the wall at various positions along the open interval is more complex. The examples given below apply to flows in either vertical or horizontal wells, however, a vertical well is used to demonstrate a case of laminar flow in which the inflow occurs over an open interval . Assuming that the flow is laminar and no mixing occurs through the flow stream lines, the fluid entering the bottom of the open interval initially fills the entire cross-section of the borehole. In addition, in the upper part of the perforation, the additional inflow of the fluids restricts the initial fluid that enters the bottom and pushes it radially inward. In the upper part of the open interval, the last fluid that enters will be in the radial region near the wall and in the initial fluid that enters the bottom will be in the center of the well. In this way, the tracker detectors can be placed in such a way that they intercept the trackers in the current that passes. The use of a turbulence generator (not shown) immediately upstream of the detector to mix the tracer current in the Bulk flow stream can be useful for this purpose. Referring again to Figure 7A, which illustrates the flow pattern for a fluid flowing at a uniform velocity within a circular tube, this flow pattern can be constructed with the following model: Assumptions: 1) Uniform inlet flow of fluids into the well; and 2) Uniform velocity profile inside the well. This assumption is somewhat contrary to what is expected from parabolic velocity profiles for flow in a tube without slippage in the walls. However, in this case where the fluids enter the wall, the flow approaches more closely to a plug flow.

Definitions: q = input flow velocity / unit length of the interval [barrels / day / foot] L = height above the lower part of the open interval [foot] L1 = fluid entry point (tracer) by above the bottom of the open interval [feet] L0 = total height of the open interval [feet] f = fraction of the well area occupied by the flow from the interval from 0 to L v = flow velocity at height L [foot / day] r0 = well radius [feet] r = flow radius of fluids in the well that enter the well below L [feet] Now consider the fluids that enter the well at a certain height L .., above the bottom of the well. At heights above this (L equal to or greater than L, the fraction of the well area in cross section occupied by fluids that fall below x is: f = qLx / qL = v pr2 / v rir02 (1) Thus, L = Lx (r0 / r): (2) The graph in Figure 8 shows the flow stream lines in a well when the fluids enter the well uniformly with depth. When the flow is turbulent, as in the case of most wells, the streamlines mix. Under these conditions, the graph in Figure 8 represents the flow fraction at a given depth (instead of the radial position) that is made up of fluids that enter the well below that depth.

To derive information regarding the movement of fluid in the well, it is necessary to understand that the time of arrival and the concentration of the trackers that can be injected in different positions in the flowing current. The use of the present invention provides ways to controllably inject a tracer material in virtually any position in the bottom of the well or detect the presence of, or concentration of, the tracer material within the flow stream in virtually any position in the lower part. from the well. Figures 9A to 9J provide only some examples of the many possible placements of the tracker injection devices 60 (which may or may not include a detector 108) and the detector devices 140 in an extraction or injection well. Again, the desirable configuration of a well typically depends on the distribution of the extraction zones 48 in a formation 32. The tracker injection devices 60 in the bottom and the detector devices 140 in the bottom may or may not be installed in a manner permanent. Permanent bottom devices are preferred due to the expense and time needed to add, remove, modify, replenish or replace a downhole device. The present invention makes it possible to permanently install downhole devices because, among other things, the present invention provides innovative ways of providing energy or communications to such permanent devices in the background. Figure 9A is a simplified diagram illustrating a possible configuration of the present invention in a vertical extraction well. In Figure 9A, there are five tracker injection devices 60 in the bottom (T ^ Ts) that are located at various locations along the vertical well depth in the production zone 48 to inject tracer materials into the stream. of flow at various depths. A bottom detector device 140 is located upstream of the tracer injection devices 60 (T ^^ - Tj) to detect tracking materials in the flow stream as they pass. The detector device 140 may comprise multiple detectors 108, each is adapted to detect a different tracer material characteristic corresponding to the different tracer injection devices 60 (Tx-T5). Alternatively, the same tracker can be used on all the injector devices and the origin of the tracker pulse is determined by selecting the injector device individually. In this way, the tracer material expelling from an average tracer injection device 60 (T3) and which is detected in the detector device 140, provides information about the flow of current entering the extraction tubing 40 in the device 60 ( T3) of medium tracer injection. The bottom detector device 140 can also be locate on the surface. But it may be more desirable in some cases to have a detector device 140 on the bottom that is located closer to the tracking injection point so that the tracked material is less diluted by fluids in the flow stream. Figure 9B is a simplified diagram illustrating another possible configuration of the present invention in a vertical extraction well. In Figure 9B, there are five bottom tracker injection devices 60 (T ^^ - Tj) that are located at various locations along the vertical well depth in the production zone 48 to inject tracer materials into the flow stream at various depths. But instead of having a detector device 140, as shown in Fig. 9A, in Fig. 9B there are five devices 140 detectors in the background, separated, in various places along the depth of the vertical well. Each detector device (S., Ss) corresponds to a tracer injection device 60 (Tx-Ts), respectively. Therefore, the detector device S4 comprises a detector 108 adapted to detect a tracer material ejected from the tracker injection device T4. In such a configuration, a detector device 140 in the same position as the tracer injection device 60 (for example, the detector device S2 and the tracker injection device T3), can be electrically connected to each other, can be electrically connected to each other. through the same induction regulator, - they can operate from the same communications and control module, they can share the same modem or they can be constituted within the same housing. Figure 9C is a simplified diagram illustrating a possible configuration of the present invention in a vertical injection well. In Figure 9C there are six detective devices 140 (Si-Sg) adapted to detect a tracer material injected into the well at the surface by a tracer injection device 60. For injection wells, it will typically only be necessary to inject the tracking materials into the surface because most or all of the flow stream originates from the surface. However, it is still possible to have one or more tracking injection devices 60 in various downward positions, in addition to, or instead of, the tracer injection device 60 on the surface. The configurations of Figures 9A to 9C can be combined so that the placement of the tracker injection devices 60 and the detector devices 140 provide tracker detection and controllable tracer injection for use during both the production and injection stages of the tracer. extraction of oil from a well. Therefore, the well can change from an extraction stage to an injection stage (and vice versa), without the need to reconfigure the tracer injection devices 160 and the detector devices 40 in the bottom, in the well. Therefore, the tracker injection devices 60 and detector devices 140 can be permanently installed for long-term use and for multiple uses. Figure 9D is a simplified diagram illustrating a possible configuration of the present invention in an extraction well having a horizontal complement. In FIG. 9D there are seven bottom tracker injection devices 60 (Tx-T7) which are located at various places along the horizontal section of the 48 d extraction zone to inject tracking materials into the tracer. -flow current in various positions. As in FIG. 9A, a detector device 140 is located in the background, upstream of the tracer injection devices (Tx-T7) to detect tracking materials in the flow stream as they pass. Figure 9E is a simplified diagram illustrating another possible configuration of the present invention in an extraction well having a horizontal termination. The configuration in Figure 9E is the same as the configuration in Figure 9B, except that the detector detectors 108 for detecting the materials in trackers are located on the surface. The detector 108 can be a self-sustaining detector device 140, or it can be part of a computer system 64 on the surface. Figure 9F is a simplified diagram illustrating another possible additional configuration of the present invention in an extraction well having a termination. horizontal. The configuration in Figure 9F is similar to the configuration in Figure 9B in that there are multiple detector devices 140 (Si-S,) corresponding to the multiple tracer injection devices 60 (Tx-T7). Figure 9G is a simplified diagram illustrating a possible configuration of the present invention in an injection well having a horizontal section. The configuration in Figure 9G is similar to the configuration in Figure 9C where there are multiple bottom detecting devices 140 (S ^ S,) adapted to detect tracer material injected into the well, on the surface by an injection device 60. tracker. In an alternative, the tracker injection device 60 can be located at the bottom. Figure 9H is a simplified diagram illustrating a possible configuration of the present invention in an extraction well having multiple side terminations. In Figure 9H, there are tracer injection devices 60 (Tx-T4) within the lateral branches, wherein each tracer injection device 60 is close to the junction between a side branch and the main well bore. Such placement of the tracker injection devices 60 (T-L-T has the advantage of facility in installation (in relation to installing a device further away at the bottom within a side branch.) A detector device 140 is located upstream of the side branch more superior. The detector device 140 is adapted to detect tracer materials injected into the side branches by the tracer injection devices T1-Ti). Therefore, the detector device 140 may comprise multiple detectors 108 adapted to detect multiple tracer material characteristics. In an alternative, the detector device 140 or detectors 108 may be located on the surface, but sometimes the bottomhole location is preferred, as shown in FIG. 9H. In Figure 91 is a simplified diagram illustrating another possible configuration of the present invention in an extraction well having multiple side terminations. In Figure 91, as in Figure 9H, there are tracer injection devices 60 (Tx-T4) at a short distance within the side branches. But in Figure 91, "there are four detector devices 140 (S - ^ - S, one for each tracer injection device (Tx-T4) respectively." Therefore, the detector device S3 is adapted to detect a tracer material injected into the flow stream by the tracer injection device T3, which provides flow information with respect to the side branch that has the tracker injection device T3 therein, because the S3 and S4 detector devices are located in the same position, can be combined in a single device 140 detector having multiple detectors 108.

Figure 9J is a simplified schematic illustrating another possible configuration of the present invention in an extraction well having multiple side terminations. In Figure 9J, the tracking injection devices 60 (Tx-T4) are located within the lateral branches near the production zones 48, and the tracker injection device (Tx) is located within the vertical portion by under the side branches. The detector devices 140 (S2-S4) are located upstream of the tracer injection devices 60 (T2-T4) respectively, within the lateral portions near the vertical section. A detector device (S) is located upstream of the tracker device T and below the lateral branches, therefore, the flow stream in each section of the well can be monitored independently For the configurations illustrated in the figures 9A to 9J, where there are multiple tracker injection devices 60 or multiple detector devices 140, the tracker injection devices 60 or the detector devices 140 can be located at evenly spaced intervals. However, the multiple tracer injection device 60 or the detector devices 140 can also be randomly separated from each other or in any other separation distribution. In addition, each of the multiple tracker injection devices 60 or devices 140 - detectors may have their own induction regulator to provide power or communications, or part or all of the tracer injection devices 60 or detector devices 140 may share an induction regulator. Because the tracker injection devices 60 and the detector devices 140 can be addressable and controlled independently, one or more sections of the well can be independently monitored. Below there are numerous calculations to illustrate how the information or measurements obtained while using the present invention can be used to determine fluid movement or flow characteristics of a well during extraction or injection. The calculations given below are established for fluid inflow into an extraction well. However, with a slight modification, they can also be applied to injection well profiles in which the tracker is injected at a position in the upper part of the range and the arrival time is observed on separate monitors throughout the open interval.

Definitions:? X. = layer thickness i [feet] h = total thickness of the interval [feet] ii = inlet flow velocity in the well per unit length from layer i [barrels / day / feet] c. = i ..? X. = flow velocity in the well from layer i [barrels / day] qt =? qx = total flow velocity in the well [barrels / day] Qx = flow velocity in the well at depth of layer i [barrels / day] Qt = total flow rate outside the well = qt [barrels / day] n = interval number (counted from the top down) N = total number of intervals v = pulse volume of injected tracer [cc] c = concentration of the tracker in the injected pulse [g / cc] vc = mass of the tracer injected [g] r = radius of the well [feet] tx = transit time through layer i Assumptions: (1)? Xj. =? x2 =? x3 = ...? xn (2) iL? -L + i2? X2 + i3? X3 ... + in? X-. = qt (without transverse flow) CASE I Uniform Input Flow ia = constant [bbls / day / feet] (3) The flow velocity in the well in layer i is the sum of the inflow velocities in all of the layers below, and in layer i: The transit time through the layer i is tx = (p r2? x / (QJ = (p r2? x /? i,? x = (p r2) / S N i (5) The total transit time from the inflow from layer k to the upper part of the interval is: t, + t, (6) ttk =?, t- (1) An example calculation is given below for four layers with a constant rate of inflow. Starting at the bottom of the interval, the flow velocity within the well increases as each layer feeds successively into the well (see table 1, column 2). For this case in which the layer thicknesses are equal, the volume of the opposite well in each layer is equal. Therefore, the transit time of fluids in the well through the layer is inversely proportional to the flow velocity in the well (see table 1, column 3). Now by adding these layer transit times from the top down, to a layer in which a tracer has been injected into the well stream, given the total transit time for a tracker to reach the top of the interval of extraction (see table 1, column 4). The injected tracer is diluted by the fluids of the inflow entering above the point of injection of the tracer. Therefore, the concentration of tracker that reaches the top of the range in relation to the initial injected concentration can be calculated by dividing the flow velocity in the well, at the point of injection between the flow velocity at the top of the interval, that is, between the total flow rate (see table 1, column 5).

TABLE 1 - Figure 10 illustrates the relative arrival times in the upper part of the range for fluids entering the well at 100 positions throughout the interval. Figure 11 illustrates the relative arrival times in the upper part of the range for fluids entering the well at 1000 positions throughout the interval.

CASE II Variable Input Flow / Variable Layer Thickness For this more complex case, the flow velocity of a fluid that enters a vertical well from a layer is a function of the permeability ratio (k), the thickness (? Yy the normalized inflow rate, determined by the pressure gradient q1 = -_ i ..? y. = flow velocity in the well from layer i [barrels / day] (8) Where, ix = constant [bbls / day / foot] Again, the flow velocity in the well in layer i is the sum of the inflow velocities in all of the layers below, and in layer i: Q = q + q? -? + • • • + Qi '(9) Where the input flow is added from the bottom up to layer i, the transit time through layer i is: ? tx = (p r2? y / (Qx) = (p r2? y /? (? i3 k3? y3) (10) The total transit time of fluids in the well from the inflow into the top layer of the interval is: (The transit times are summed for layer 1 in the upper part of the interval, down to the layer i) ? tTl =? tx +? ts +? t, (11) ? tti = S ^? tk '(12) Wells with Multiple Side Horizontal Terminations When the wells are completed with multiple horizontal side branches, as shown in Figures 9H to 9J, the productivity of the individual branches can not be determined by conventional records or profile measurements. The information regarding the productivity of the individual lateral parts should be useful in the administration of deposits that can lead to reboiling or filling wells in the direction of the side branches poorly completed. Similarly, if production from a well, as seen on the surface, shows a sudden increase in water or gas, it is useful to determine which side branch causes the problem. In the simplest application of the use of trackers for the diagnosis of lateral wells, the point of injection of tracer can be located at a short distance within the lateral branch by any of the methods of placement discussed above (see figures 9H and 91). . The detector can be located in the vertical section of the well above the uppermost lateral branch. Lateral branches that have low productivity will show a large diluted tracer response, because the transit time on that side branch is prolonged, compared to that which occurs in the vertical tube.

Injection Wells with Large Vertical Open Intervals In formations that are flooded with water during prolonged intervals, the maintenance of uniform injection profiles is essential to ensure the efficient flooding of the entire petroleum zone. In a typical completion of an injection well, fluid is injected through the tubing under a packing seal and allowed to enter the target zone through perforations in the coating tube or through a stencil lining. In this application, many detectors may be installed along the liner or liner, or preferably along a perforated extension of the tubing below the packing plug (see Figure 9C). With this configuration, the tracker can be injected on the surface, and the arrival time of the various detectors used to determine the injectivity profile. With readings on the surface of the detectors, a complete history of the fluid injection profile can be obtained through the flooded area. In the case of wells being injected, particular care must be taken to mix the injected tracer carefully to avoid segregated flow near the wall of the tube. The reason for this is that the fluids that leave the well in the wall; and therefore the tracker that remains near the wall will leave the well in the upper layers and will not be available for measurements in the lower zones. An example is provided below to demonstrate how the times of arrival of the tracker observed in widely separated monitors can be used to calculate the injection profile in a heterogeneous range consisting of zones having widely varying permeabilities.

Example of Water Injection Well: Diameter: 15.2 cm (6 inches ^ Well completion: 30.8 m (101 ') of unperforated pipe below the packing plug; 152 m (500 ') of perforated interval; Total injection speed: 800 barrels per day. Injection Profile: see Figure 1 TABLE 2 INJECTION PROFILE The tracker injection into the packing shutter, 30.8 m (101 ft) above the open interval; Tracker monitoring devices 15 m (50 ') apart over the open interval.

The time in minutes for the tracker to move from one position to the next is: = (p r2) (? y / (Q (13) = [(p /.) (l / d) 2 (1440) /5.615] (? y / (Q = [(201.42) (1 / d) 2] (? y / ÍQ = [(201.42) (l / 2) 2 (? Y / (Q tx = (50.355) (? Y / (Q (14) Therefore, the time for the tracker to move from the injection point to the upper part of the open interval is: t0 = (50.355) (? Y0) / (Q0) t0 = (50.355) (101) / (800) = 6.357319 minutes Subsequently, the speed in the well decreases as the water leaves the perforated interval. Using very short intervals (? And .. = 30.48 cm (1 foot)), the inverse of the transit time speed (? Tx) can be calculated for each depth: ? t, = (50.355) (? and / (Qavg) = (50.355) (? y / (Q - ^ + Q / 2 (15) For the first 30.5 m (100 ft), the injectivity is 1 b / d / foot,? t, = (50.355) (1) / (800 + 799) / 2 = 0.062983 min? t2 = (50.355) (1) / (799 + 798) / 2 = 0.063062 min ? t100 = (50,355) (1) / (701 + 700) / 2 = 0.071884 min For the second 30.5 m (100 ft), the Injectivity is 4 b / d / ft, ? t101 = (50,355) (1) / (700 + 696) / 2 = 0.072142 min ? t2Q0 = (50.355) (1) / (304 + 300) / 2 = 0.166738 min For the third 30.5 m (100 ft), the injectivity is 0 b / d / ft, ? t, = (50,355) (1) / (300 + 300) / 2 = 0.16785 min ? t2a? = (50,355) (1) / (300 + 300) / 2 = 0.16785 min For rooms 30.5 m (100 ft), the injectivity is 1 b / d / ft, ? t30i = (50.355) (1) / (300 + 299) / 2 = 0.16813 min ? t400 = (50.355) (l) / (201 + 200) / 2 = 0.25114 min For the fifth 30.5 m (100 ft), the injectivity s 2 b / d / ft, ? t40 (50,355) (1) / (200 + 198) / 2 = 0.25304 min ? t500 = (50,355) (l) / (2 +0) / 2 = 50,335 min Figure 13 shows that these calculations closely approximate the actual flow velocities that would be observed in a well with the injection profile given above. Figure 14 shows the cumulative sum of the totality of the interval times: * - tv * - • n + S, 500? t, of; and we observe that only minimal changes are observed in the arrival times in this exhibition although the injectivities vary from 0 to 4 b / d / ft. The number of surveillance points is limited by practical considerations. If the tracker surveillance modules are separated at 15.2 m (50 ft) intervals, the arrival times in these positions can be used to calculate the injection speeds as a function of depth, as follows: tso = t0 +? tso (17) = t0 + (50.355) (? y50) / (Q50 + Q0) / 2 (18) Knowing that the flow velocity that is injected into the well and the arrival times of the tracker in the upper part of the open interval and 15.2 m (50 feet) below, we can calculate the velocity in the well at that depth (Qsa), Qso = [(100.71) (? Y50) / (t50-t0) - Q0 (19) = [(100.71) (50) / (9.607156-6.357319)] - 800 = 749.4624 B / D Using the calculated speed and the arrival times of the tracker at that depth, one can solve the flow velocity (Q100) in the next monitor from the arrival time at that depth (30.5 m (100 feet)).

Q100 = [(100.71) (50) / (13.08129-9.607156)] - 749.4624 = 699.9629 B / D Next, we calculate the flow rates of each monitor down to the bottom of the interval. Figure 15 compares the actual flow rates with the values calculated from readings at 15 m (50 feet). Correspondence is good, except for the location in the background, where the flow speed returns to zero and the transit times become infinite. This method of calculating flow velocities can also be applied to a larger separation. However, when the fraction of total flow that enters the formation in the interval between two monitors is large compared to that which passes in the upper monitor, significant errors are introduced. For example, if a separation of 31 m (100 ft) is used, in the previous calculation, the - The predicted flow velocity is too low in zone II where the actual well flow rate decreases from 700 b / d to 300 b / d, as shown in figure 15. The reason for this deviation is the use of velocity flow average of the interval for coincidence of the transit time of the interval. If the transit time of the zone (? T-) is matched to a series of Ns transits of the subzones, each of which reflects an equal loss of fluid within the formation, a flow velocity is obtained as follows corrected at the bottom of the zone (QN):? t, = (50.355) (? yn). { [l / Q0] + [1 / (l / N.) (Q0-Q] ++ [1 / (2 / N ") (Q0-QN)] + [1/3 / N) (Q0-QN) ... + [1 / (N./N.) (Q0-Q (20) ? t, (Q0) / (50.355) (? yn) =. { [1] + [1 / (1- (1-N.) + (L / N.) (QN / Q0))] + + [1 / (1- (2 / Ns) + (2 / Nß) ( QN / Q0))] + + [1 / (1- (3 / Ns) + (3 / Ns) (QN / Q0))] + + [1 / (1- (N./Ns) + (N./Ns) (QN / Q0))]} (21) The transit time of the zone (? Tx) is known from the observations of arrival time in the upper part and in the bottom of the zone. The thickness of the subzone (? And n) is equal to the thickness of the zone divided by the number of selected subzones (Ns). The flow velocity of the well in the upper part of the zone (Q0) is obtained from the calculated value of the flow velocity in the base of the previous zone. The flow velocity at the bottom of the present zone (Q ") is obtained by repetition since an explicit QN solution is not available in equation 21.

Extraction Wells with Large Vertical Open Intervals The inflow profiles of vertical extraction wells of large intervals can be analyzed by a method similar to that described above. However, there are some differences that must be taken into consideration. In an injection well, the tracer can be injected at a single point on the surface in the flow stream that moves at maximum speed (see Figure 9C). The tracker will pass along the well at a rate that decreases. The only part of the well not susceptible of arrival of the tracker is in the section that is very deep, where the speed of flow becomes negligible. In the case of an extraction well, the tracker must be injected below the interval to be analyzed (see Figures 9A and 9B). Near the bottom, the flow rates become small and the concentrations of the trackers are continuously diluted by the inflow from the formation as the tracker moves up. In practical applications, the arrival times of the tracker injected near the bottom will be too large and its concentration will be too low to obtain useful information in the upper part of the deposit. A less complete definition of the productivity profile can be obtained by using pairs of tracker injection modules with detection modules. Unlike injection wells where the tracer moves radially outward as the flow current moves down the orifice, the extraction wells show an inward radial movement as the fluids that are produced move up the orifice . Unless mixing occurs, a tracer injected into the well will eventually occupy the center of the well as it flows up the well. This means that there is no danger of the tracker leaving the well, but caution must be taken at the point of detection to avoid losing the tracer's step when the detector is located on the wall. One possible solution is the use of turbulence generators in the well that are located immediately below the detectors to ensure that the tracker passes through the wall. The above analyzes assume a dominant phase that flows into the well that can be observed by a single tracker. In practice, most extraction wells have combinations of oil, water and gas that flow into the well. Under these conditions, flotation forces can result in rapid phase transport in Comparison with the average fluid velocity. There are a wide variety of downhole conditions in commercial oil and gas wells, and many opportunities are available for the use of downhole detectors for specific production conditions. These conditions will be evident for those experts in the practice of extraction wells. An example of useful information that can be obtained by such devices is the position of the water or gas inlet points. In flooding with water, there is often a difference in the salinity of the original reservoir water and the floodwater injected. The arrival of fresh water to the surface in the individual wells of a well flooded with water has been used for many years to monitor ruptures. However, in wells with large intervals there is no easy way to learn the area in the vertical section that is in rupture. Permanently mounted detectors that are located along the open interval can be used to monitor the progress of a flood and provide guidance for correction work to exclude water breakage. An example calculation is provided below to demonstrate how the arrival times of fluids extracted at the top of a range can be used to infer productivity profiles as a function of depth. In this calculation, they use equations 3 to 12 that are provided before Example of a Vertical Extraction Well TABLE 3 ADIMENSIONAL PRODUCTIVITY PROFILES Figure 16 shows the cumulative fluid inflow as a function of depth for these four profiles. Figure 17 compares arrival times for the cases of diagrams A to C as defined in table 3 and figure 16. Compared to a uniform inflow profile, large differences in arrival times are observed when the flow is not uniform. In each of these profiles, the total adimensional flow velocity is 1.0. For a uniform input flow, the velocity per unit depth is IX.

When the entire flow is in the upper half, at a speed of 2X (diagram A), there is no transport of fluid in the lower half and the arrival time becomes infinite for a fluid that enters the midpoint of the interval. When the entire flow is in the lower half at a speed of 2X (diagram B), arrival times are short across the interval. When the flow velocity occurs only at the bottom and top, 10% of the interval at 5X (diagram C), the fluid transit times from the bottom are faster than from the uniform case and they become slower than the uniform case for fluids that enter near the top. Figure 18 shows that the relative arrival times forms are distinctive of the various profiles and therefore the productivity profiles can be estimated using a series of separate tracer injection points throughout the interval (see Figures 9A and 9B). In addition to arrival times, the concentration of a crawler tap that reaches the top of the range from positions along the open interval can be used to verify the interpretation of a productivity profile. Dilution of a tracker plug by the entire fluid inlet flow above the point of injection of the tracker is assumed, so that it is calculated in column 5 of table 1. Figures 19, 20, 21 and 22 show tracker concentrations and arrival times in the upper part of the training for the four profiles.

Production Wells with Large Horizontal Open Intervals. Unlike vertical wells with terminations, wells with large horizontal terminations are usually completed in a single geological layer and therefore their productivity profiles depend less on the distances in layer permeabilities. In these wells, the maintenance of uniform profiles is equally important. However, the pressure gradient over the open interval tends to result in higher extraction velocities at the bifurcation compared to the end of the well due to the higher downward drag pressure that can be obtained near the vertical section (the bifurcation). The high rates of extraction in portions of the open interval can lead to the formation of early gas cones from the top of the oil extraction elevation or formation of water cones from the bottom of it. Surveillance of the tracker, with separate devices in the horizontal portion (see Figures 9D to 9G) may be useful in providing information about proper control of inflow into these wells. The magnitude of the high productivity at the bifurcation can be examined by calculating the effect of a distributed inlet flow of a fluid from the formation on the pressure drop along the wellbore. The following calculation illustrates the effect.

Example of Horizontal Well Analysis L = length of the entire open interval (feet) N = number of surveillance points (subsections) L = L / N = separation of the monitors [feet] n = index of the subsection (from the end to the fork) Q? = total flow velocity of the well [b / d] P? = total pressure drop over the open interval [psi] PH = head loss from the flow in the well [(psi / feet) / (b / d)] dqf = specific inflow velocity with uniform profile from the reservoir in the well [b / d / ft]? qf = inflow velocity from the reservoir in a subsection of the well [b / d]? q-. = flow velocity in the well in subsection (n) [b / d]? pn = pressure drop in subsection n = pH (? L) (? q-.) [psi] Assuming the well is subdivided into? well sections, from the upper stream (end to bifurcation), n = 1, 2.,? (22, ' With uniform input flow, ? q £ =? L (QN / L) [1, 1, 1, 1, ... 1] (23) The flow velocity in the well accumulates as the inflow from the end to the bifurcation occurs , ? qn? L (QN / L) [1,2,3,4, ... N] (24) It is assumed that the pressure drop to each subsection is proportional to the flow velocity, therefore, ? pn? L (? qn) (pH) [1,2,3,4-N] (25) By adding the pressure drops to each subsection, the total pressure drop in the well from the end to the downstream subsections is successively: Pn Sa? L (? Q (pH) (n) (n + l) / 2) (27) Pn? L (? Q (pH) [1,3,6,10,15, ... N (N + l) / 2] (28) Assumptions: length of the entire open interval = 762 m (2500 ft) separation of the monitors = 30.5 (100 ft) total flow velocity of the well = 250 b / d specific head loss in the well = 10"psi / b / d / ft Inlet Flow at Well End, No Inlet Flow Throughout Interval (1) For a well in which all of the 2500 barrels flow through 762 m (2500 ft) of the well, the pressure drop would be: (QN) (L) (pH) = (2500) (2500) (10 ~ 4) = 4309 kPa (625 psi) (29) Uniform Input Flow (2) For a well that draws uniformly along 25 subdivisions (controllable well sections), the total pressure drop in its open range, calculated by equation 26 is: (? q (? L ((pH) [N (N + l) / 2] = (100) (100) (10"4) (25) (26) / 2 2241 kPa (325 psi) (30) Input Flow Dependent on Reservoir Pressure The inlet flow velocity in the well is proportional to the difference between the reservoir pressure and the pressure in the well. Because the pressures in the well over the open interval depend on the flow rate, the inflow profile must be obtained by a repetitive calculation. We define the reservoir pressure (pres) as a certain pressure (p0) above the highest pressure in the well, that is, the pressure at the end.

The pressure difference between the reservoir pressure and the pressure in the well at downstream positions from the endpoint is: ? P = (p0 + ptoe) - (ptoe - pn) = Po + pp (32)? P¡ = po + S? L (? Q ") (p?) ((N) (n + l) / 2 ) (33) In the first repetition, the cumulative flow and the cumulative pressure drop across the tubing can be calculated by adding the pressures of the input flow differential (p0 + pn) and normalizing the subsection differential pressures with that sum: Sum? Pl = S ± N? Pl (34) ? p- Normalized? px = Pi = (35) Sum? px = = SXN? px The input flow velocity of each subsection is proportional to this normalized differential pressure, therefore, the input flow velocity of each subsection is: The cumulative flow that occurs in the well is: Qx = S qx (? L) (37) and the cumulative pressure drop in the well from the end to the bifurcation is: pnl = SS qx (? L) (pH) (38) A second repetition is performed by substituting these values for the pressure drops in equation 31. The convergence is fast - in this case very few repetitions are needed. This can be done by substituting the successive values of in equation 34 Figure 23 presents the results of these pressure drop calculations for various flow conditions of entry. When all flows entering the well as the end (case 1-tubing open end), the cumulative pressure drop across the tubing is large since each section of the tube experiences the maximum pressure drop. When the flow is uniform along the length of the horizontal well section (case 2 - uniform inflow), smaller pressure drops occur near the end where the flow velocities in the well are low. For the same total flow rate of 2500 b / d, a uniform inflow case results in only about half of the total pressure drop 2241 kPa, (325 psi) compared to case 1, where the fall Total pressure is 4309 kPa (625 psi). When the input flow depends on the reservoir pressure (case 3 - non-uniform input flow), an even lower pressure drop occurs. If the pressure in the reservoir exceeds only the pressure of the well tip slightly and the pressure drop in the well is large in comparison, then most of the inflow occurs near the bifurcation. The lower limit occurs when the tank pressure is equal to the pressure at the wellhead (ie, p0 = 0). In that case, the total pressure drop is 862 kPa (125 psi). The upper limit, when the reservoir pressure becomes large (p0 = oO), results in a uniform inflow. Figure 24 shows the calculated flow rates resulting from various flow conditions of reservoir entry. The flow velocities that occur along the horizontal well section under the conditions indicated above can be normalized with respect to flow rates in a well with uniform inflow. Therefore, using the present invention and the calculations provided herein, flow streams in a production or injection well can be monitored and characterized in real time, as needed. The information provided by the use of the present invention can provide more insight into the cases that occur downhole and can be used to guide operators or a computer system to alter extraction or injection procedures to optimize the operations. Such uses can greatly increase efficiencies and maximize the extraction of oil from a given reservoir. The present invention can also be applied to other types of wells (other than oil wells) such as water extraction wells. It will be appreciated by those skilled in the art that by having the benefit of this disclosure that this invention provides, an oil extraction well having at least one electrically controllable tracer injection device, as well as methods of using such devices to monitor the extraction in the well. It should be understood that the drawings and the detailed description in - the present are considered illustrative rather than limiting, and are not intended to restrict the invention to the particular forms and examples that are described. On the contrary, the invention includes any modification, change, rearrangement, substitution, alternative, choice of design and additional modality, evident to a person usually skilled in the art, without departing from the spirit and scope of this invention, as defined by the following claims. Therefore, it is intended that the following claims be construed to encompass all such modifications, changes, rearrangements, substitutions, alternatives, design choices and modalities. It is noted that in relation to this date, the best method known to the applicant to carry out the aforementioned invention is that which is clear from the present description of the invention.

Claims

CLAIMS Having described the invention as above, the content of the following claims is claimed as property: 1. A tracer injection system for use in a well characterized in that it comprises: a current impedance device that is generally configured to be placed around a portion of the well casing structure and to prevent an electrical signal that varies with respect to the time transported along the portion of the well casing structure and to limit the electrical signal that varies with respect to the time transported to the well. along a portion of the tubing structure; and an electrically controllable tracer injection device, downhole, adapted to be electrically connected to the tubing structure, adapted to be energized by the electrical signal that varies with respect to time and adapted to eject a tracer material in the hole.
2. The tracker injection system according to claim 1, characterized in that the current impedance device generally has a ring-shaped geometry and comprises a ferromagnetic material.
3. The tracker injection system, according to claim 1, characterized by the The tubing structure comprises at least a portion of the well extraction tubing, the electric return comprises at least a portion of the well liner, from the extraction well.
4. The tracker injection system, according to claim 1, characterized in that the casing structure comprises at least a portion of the well casing.
5. The tracker injection system according to claim 1, characterized in that the injection device comprises an electric motor and a communications and control module, the electric motor is electrically connected and is adapted to be controlled by the module of communications and control.
6. The tracker injection system, according to claim 1, characterized in that the injection device comprises an electrically controllable valve and a communications and control module, the electrically controllable valve is electrically connected and adapted to be controlled by the communication and control module.
7. The tracker injection system, according to claim 1, characterized in that the injection device comprises a deposit of tracer material and a tracer injector, the tracer material deposit is in fluid communication with the tracer injector, the tracer injector adapts to expel - - from the injection device and the tracer material from inside the tracer material reservoir in response to an electrical signal.
8. The tracker injection system, according to claim 1, characterized in that the electrical signal is an energy signal.
9. The tracker injection system, according to claim 1, characterized in that the electrical signal is a communication signal for controlling the operation of the tracker injection device.
10. The tracker injection system, according to claim 1, characterized in that it further comprises a detector adapted to detect a tracer material, the tracer material passes the detector in a flow stream.
11. The tracker injection system, according to claim 1, characterized in that it further comprises a nozzle extension tube extending from the tracker injection device.
12. An oil well for extracting petroleum products, characterized in that it comprises: a tubing structure placed within the well bore, from the extraction well; a current impedance device placed around the casing structure to define an electrically conductive portion of the casing structure; a signal source that varies with respect to time electrically connected to the electrically conductive portion of the tubing structure; and an electrically controllable tracer injection device, which is electrically connected to the conductive portion and which is adapted to be coupled to the signal that varies with respect to time.
13. The oil well, according to claim 12, characterized in that the current impedance device comprises an energy activated conduction regulator comprising a ferromagnetic material, so that the induction regulator operates based on its size, geometry , spatial relationship with the tubing structure, and magnetic properties.
14. The oil well, according to claim 12, characterized in that the casing structure comprises a production casing and a well casing, the time variation signal is applied to at least one of the casing and the casing.
15. The oil well, according to claim 12, characterized in that the tracker injection device comprises an electrically controllable valve.
16. The oil well, according to claim 12, characterized in that the tracker injection device comprises an electric motor. -
17. The oil well, according to claim 12, characterized in that the tracker injection device comprises a modem.
18. The oil well, according to claim 12, characterized in that the tracer injection device comprises a reservoir of tracer material.
19. The oil well, according to claim 12, characterized in that it further comprises a detector adapted to detect a tracer material.
20. The oil well, according to claim 12, characterized in that it further comprises a nozzle extension tube extending from the tracer injection device.
21. An oil well for extracting petroleum products, characterized in that it comprises: a well liner that extends into the well of the extraction well; an extraction tubing that extends into the lining; an electric current source that varies with the time it is located on the surface, the current source is electrically connected and adapted to a current output that varies with time within at least one of the tubing and the sheath; a downhole tracker injection device comprising a communications module and control, a deposit of tracer material and an electrically controllable tracer injector, the communications and control module is electrically connected to at least one of the casing and the casing, the tracer injector is electrically connected to the communications and control module, the Tracer material deposit is in fluid communication with the tracer injector; a downhole current impedance device that is located around a portion of at least one of the casing and casing, the current impedance device is adapted to direct part of the electrical current through the communications module And control .
22. The oil well, according to claim 21, characterized in that it includes a detector device that is electrically connected to at least one of the tubing-and the liner, the detector device comprises a detector adapted to detect a tracer material in a Well flow stream.
23. The oil well, according to claim 21, characterized in that it further comprises a nozzle extension tube extending from the tracer injector.
24. The oil well, according to claim 21, characterized in that the tracker injector comprises an electric motor, a screw mechanism and a nozzle, the electric motor is connected electrically to the communications and control module, the screw mechanism is mechanically coupled to the electric motor, the nozzle extends into the interior of the tubing, the nozzle provides a passage of fluid between the reservoir of tracer material and the interior of the tubing, and the The screw mechanism is adapted to drive the tracer material out of the deposit of tracer material and into the interior of the tubing by means of a nozzle, in response to a rotational movement of the electric motor.
25. The oil well, according to claim 21, characterized in that the deposit of tracer material comprises a separator therein that divides the interior of the tracer material deposit into two volumes, and wherein the tracer injector comprises a valve. Electrically controllable and a nozzle, the first of the inner reservoir volumes contains a tracer material, the second of the inner volumes of the reservoir contains a pressurized gas so that the gas exerts pressure on the tracer material in the first volume, the controllable valve electrically electrically connected and controlled by the communications and control module, the first volume is connected fluidly to the interior of the tubing by means of an electrically controllable valve and by means of a nozzle.
26. The oil well, according to claim 21, characterized in that the deposit of tracer material comprises a separator therein. dividing the interior of the tracer material deposit into two volumes, and wherein the tracer injector comprises an electrically controllable valve and a nozzle, the first of the inner reservoir volumes contains a tracer material, the second of the inner volumes of the reservoir contains a spring element so that the spring element exerts pressure on the tracer material in the first volume, the electrically controllable valve is electrically connected and controlled by the communication and control module and the first volume is fluidly connected to the interior of the tubing by means of an electrically controllable valve and by means of a nozzle.
27. The oil well, according to claim 21, characterized in that the current impedance device comprises an induction regulator without power, comprising a ferromagnetic material.
28. The oil well, according to claim 21, characterized in that the downhole injection device further comprises a detector, the detector is electrically connected to the communications and control module and the detector is adapted to detect a tracer material .
29. The oil well, according to claim 21, characterized in that the communication and control module comprises a modem.
30. A method for operating an oil well, characterized in that it comprises the steps of: providing a tubing structure that extends into a drill hole of the extraction well; apply electrical current that varies with time, to the tubing structure; provide energy to the downhole tracker injection system from the well using electric current that varies with time, applied to the tubing structure; and injecting tracer material from the tracer injection system into the downhole flow stream into the extraction well.
31. The method of compliance with the claim 30, characterized in that it further comprises the steps of: monitoring the flow stream in a position remote from the tracer injection device; and detecting the tracer material within the flow stream.
32. The method according to claim 30, characterized in that it further comprises the step of: transmitting data corresponding to the detection steps to a computer system on the surface via the tubing structure.
33. The method according to claim 30, characterized in that it also comprises the step of: - - place a deposit of tracer material in the well's main well bore; injecting the tracer material into the lateral branch that extends from the main well perforation via a capillary that extends into the lateral branch. - SUMMARY OF THE INVENTION An oil well (20) comprising a well casing (30), a production tubing (40), a current source (68) that varies with time, a tracer injection device (60) is provided in the bottom, an induction regulator (90) in the background. The liner (30) extends into a well borehole (20). The tubing (40) extends into the liner (30). The current source (68) is located on the surface. The current source (68) is electrically connected and adapted to transmit current that varies with time within the pipe (40) or the liner (30), which act as electrical conductors to provide power and communications at the bottom. the injection device (60). The injection device (60) comprises a communications and control module (80), a reservoir (82) of tracer material, and an electrically controllable tracer (84). The communication and control module (80) is electrically connected to the tubing (40) or the liner (30). The induction regulator (90) in the bottom is located around a portion of the tubing (40) or the liner (30). The induction regulator (90) is adapted to direct part of the electric current through the communication and control module (80) by generating a voltage potential between a side of the regulator (90) of > 2- ßSo & induction and the other side of the induction regulator (90). The communication and control module (80) is electrically connected through the voltage potential. The hole (20) may further comprise a detector (108) or a detector device (140) which is located upstream of the injection device (60) which is adapted to detect the tracer material injected into the well by the injection device. The detector device (140) may also be in the background and may comprise a modem (146) to send data to the surface via the tubing (40) or the liner (30). ol l So ß