NO326367B1 - Tracer injection system in a petroleum production well - Google Patents

Description

The present invention relates to a petroleum well for producing petroleum products. In one aspect, the present invention relates to systems and methods for monitoring fluid flow during petroleum production by controllably injecting tracer materials into at least one fluid flow with at least one electrically controllable downhole tracer injection system for a petroleum well.

The controlled injection of materials into petroleum wells (ie oil and gas burners) is an established practice that is often used to increase recovery, or to analyze production conditions. It is useful to distinguish between types of injection, depending on the quantities of materials that will be injected. Large volumes of injected materials are injected into formations to displace formation fluids towards the production well. The most common examples are water flooding.

In less extreme cases, materials are introduced downhole into a well to effect treatment inside the well. Examples of these treatments include: (1) foaming agents to improve the effectiveness of artificial lift; (2) paraffin solutions to prevent deposits of solids in the pipe; and (3) surface active materials to improve the flow characteristics of produced fluids. These types of treatments include modification of the well fluids themselves. Less quantity is required, but still these types of injection are typically delivered by additional pipes routed downhole from the surface.

Still other applications require even smaller amounts of materials to be injected, such as: (1) anti-corrosion materials to prevent or reduce corrosion of the well equipment; (2) scale stoppers to prevent or reduce scale formation on the well equipment; and (3) tracer materials to monitor the flow characteristics of different well sections. In these cases, the quantities required are small enough that the materials can be delivered from a downhole reservoir, avoiding the need to run supply pipe down the hole from the surface. Successful application of techniques requiring controlled injection from a downhole reservoir, however, requires that the device must be equipped to drive and communicate with the injection equipment downhole. In existing practice, this requires the use of electrical cables that run from the surface to the injection modules in the depth of the well. Such cables are expensive and not entirely reliable, and as a result they are considered undesirable in current manufacturing practice.

The use of tracer materials to identify materials and follow their flow is an established technique in other industries, and the development of tracer materials and detectors has continued to the point where the materials can be sensed in resolutions down to IO"<10>, and millions of individually identifiable marks are available.The representative leading supplier of such materials and detection equipment is Isotag LLC of Houston, Texas.

The use of tracer materials to determine flow patterns has been applied in a variety of research fields, such as the observation of biological circulatory systems in animals and plants. It has also been offered as a commercial service in the oil field, e.g. as a means of analyzing injection profiles. The use of tracer agents for production in the oil field is, however, an exception, since existing methods require the insertion into the borehole of special equipment driven and controlled using cables or hydraulic lines from the surface to the depth of the well.

For other known techniques, we can refer to EP 721 053 Al.

All references mentioned herein are incorporated by reference to the maximum extent permitted by law. To the extent a reference is not fully incorporated herein, it is incorporated by reference for background purposes, and indicates the knowledge of a person of ordinary skill in the art.

According to the invention, this is achieved with the device according to the present invention as defined by the features stated in the claims.

The invention shall be described in more detail in the following in connection with some exemplary embodiments and with reference to the drawings, where Figure 1 is a diagram showing a petroleum production well according to a preferred embodiment of the present invention; figure 2A is a diagram of an upper part of a petroleum well according to another preferred embodiment of the invention; figure 2B is a diagram of an upper part of a petroleum well according to another preferred embodiment of the present invention; Figure 3 is an enlarged view of a downhole portion of the well in Figure 1; Figure 4 is a simplified electrical diagram of the electrical circuit formed by the well in Figure 1; Figures 5A through 5D are schematics of various casing injection and casing material reservoir embodiments for downhole electrically controllable tracer injection devices of the present invention; figure 6 is a diagram of a sensor device in a petroleum well according to the present invention; Figures 7A through 7E are schematics of steady inflow and injection profiles for various well configurations; figure 8 is a plot illustrating fluid streamlines in a laminar flow circular door in the case where the fluid enters the tube uniformly at its wall along the length of the tube; Figures 9A through 9J are simplified diagrams illustrating examples of different configurations for placement of the tracer injection device and sensor devices in a variety of well configurations; figure 10 shows in graphical form normalized arrival times on the ordinate as a function of a normalized depth and the abscissa for a simulation of inflow using 100 inflow zones; figure 11 shows normalized arrival time on the ordinate as a function of normalized depth on the abscissa for simulation of inflow using 1000 inflow zones; Figure 12 defines the injectivity profile of an illustrative injection well by showing the injectivity profile on the ordinate as a function of depth on the abscissa; figure 13 shows the tracer material transit time per unit length of the illustrative injection well defined in figure 12 by showing transit time on the ordinate as a function of depth on the abscissa; figure 14 shows the arrival time of the tracer material in the illustrative injection well defined by figure 12 by showing the arrival time on the ordinate as a function of the depth on the abscissa; Figure 15 compares calculated and actual injection rates as a function of depth in the illustrative injection well defined by Figure 12 by showing injection rate on the ordinate as a function of depth on the abscissa; Figure 16 defines four illustrative cases of production wells by showing cumulative inflow on the ordinate as a function of depth on the abscissa; Figure 17 shows normalized arrival time for an injected tracer material on the ordinate as a function of depth for four illustrative cases of petroleum wells defined in Figure 16; figure 18 shows the normalized arrival time of an injected tracer material relative to the case of uniform injection rate on the ordinate, as a function of depth for the four illustrative cases of production well defined in figure 16; Figure 19 shows the relative concentration of tracer pulses on the ordinate as a function of arrival time on the abscissa for a case of steady inflow over a production interval; Figure 20 shows the relative concentration of tracer pulses on the ordinate as a function of time of arrival on the abscissa for an illustrative case of non-uniform inflow over a production interval; Figure 21 shows the relative concentration of tracer pulses on the ordinate as a function of time of arrival on the abscissa for another illustrative case of non-uniform inflow over a production interval; Figure 22 shows the relative concentration of tracer pulses on the ordinate as a function of arrival time on the abscissa for a third illustrative case of non-uniform inflow over a production interval; figure 23 shows cumulative pressure drops along the pipe on the ordinate as a function of the distance along a horizontal well on the abscissa, for various illustrative cases of the difference between reservoir pressure and well-toe pressure in horizontal completion wells; and Figure 24 shows relative inflow rates per unit length on the ordinate as a function of distance along a horizontal well on the abscissa for various illustrative cases of differences between reservoir pressure and well-toe pressure in a horizontal completion well.

Reference is now made to the drawings, where like reference numbers are used to designate like elements throughout the different views, where preferred embodiments of the invention are illustrated and further described. The figures are not necessarily drawn to scale, and in some cases the drawings are exaggerated and/or simplified in places for illustrative purposes only. A person of ordinary skill in the art will appreciate that many possible applications and variations of the present invention based on the following examples of possible embodiments of the present invention, as well as based on the embodiments illustrated and described in 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 string, well casing, a pump rod, a series of interconnected pipes, rods, rails, trusses, trusses, supports, a branch or lateral extension of a well, a networks of interconnected pipes, or other similar structures known to one of ordinary skill in the art. A preferred embodiment makes use of the invention in the context of a petroleum well where the pipe structure comprises pipes, metal pipes, electrically conductive pipes or pipe strings, but the invention is not limited to this. For the present invention, at least part of the pipe structure needs to be electrically conductive, such electrically conductive parts can be whole pipe structures (e.g. steel pipes, copper pipes) or longitudinal electrically conductive parts combined with a longitudinal non-conductive part. In other words, an electrically conductive pipe structure is one that provides an electrically conductive path from a first area where the power source is electrically connected, to another area where the device and/or electrical return is connected. The pipe structure will typically be conventional round metal pipes, but the cross-sectional geometry of the pipe structure or parts thereof may vary in shape (e.g. round, rectangular, square, oval) and size (e.g. length, diameter, wall thickness) along any part of the pipe structure. Therefore, a pipe structure must have an electrically conductive part which extends from a first part of the pipe structure to another part of the pipe structure, where the first part is at a distance from the second part along the pipe structure.

The terms "first part" and "second part" as used herein are each defined generally to refer to a part, section or area of a pipe structure which may or may not extend along the pipe structure, which may be located at any location along the pipe structure, and which may or may not include the nearest ends of the pipe structure.

The term "modem" is used herein to generally refer to any communication device for sending and/or receiving electrical communication signals via an electrical wire (eg, metal). Therefore, the term "modem" as used herein is not limited to the acronym for a modulator (a device that converts a voice or data signal into a form that can be transmitted)/demodulator (a device that receives an original signal after modulating a high frequency carrier) . Also, the term "modem" as used herein is not limited to conventional computer modems that convert digital signals to analog signals and vice versa (eg, to transmit digital data signals over the analog public telephone network). For example, if a sensor outputs measurements in analogue form, such measurements only need to be modulated (eg spread spectrum modulation) and sent - therefore no analogue/digital conversion is required. As another example, a relay/slave modem or communication device may only need to identify, filter, amplify and/or relay 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 lift gas into a tubing string of an eri well. The internal and/or external functions of the valves can vary greatly, and in the present application, it is not intended to limit the valve as described to any particular configuration, as long as the valve functions to regulate flow. Some of the different types of flow control mechanisms include, but are not limited to, ball valve configurations, needle valve configurations, gate valve configurations, and cage valve configurations. The procedure for installing valves as described in the present application can vary greatly.

The term "electrically controllable valve" as used herein generally refers to that valve (as just described) that can be opened, closed, adjusted, altered or throttled, continuously in response to an electrical control signal (eg, a signal from a surface computer or from a downhole electronic control module). The mechanism that actually moves the valve position may include, but is not limited to: an electric motor; an electric servo; an electric solenoid; an electric switch, a hydraulic actuator controlled by at least one electric servo, electric motor, electric switch, electric solenoid or combinations thereof, a pneumatic actuator controlled by at least one electric servo, electric motor, electric switch, electric solenoid, or combinations thereof ; or a spring-based device in combination with at least one electric servo, electric motor, electric switch, electric solenoid, or combinations thereof. An "electrically controllable valve" may or may not include a position feedback sensor to produce a feedback signal corresponding to the current position of the valve.

The term "sensor" as used herein refers to any device that detects, determines, monitors, records or otherwise senses the absolute value or a change in a physical quantity. A sensor as described herein can be used to measure physical quantities, including but not limited to: temperature, pressure (both absolute and differential), flow rate, seismic data, acoustic data, pH level, salt level, valve positions, volume or almost any any other physical data. A sensor as described here can also be used to detect the presence or concentration of a trace material within a stream.

The term "at the surface" as used herein refers to a place or position less than about 16 m deep in the earth. In other words, the phrase "at the surface" does not necessarily mean sitting on the earth at ground level, but is used in a broader sense here to refer to a place that is often easily or conveniently accessible or a wellhead where people can work. For example, "at the surface" may be on a table in a workroom located on Earth at one well platform, it may be on an ocean floor or a seabed, may be on a deep-sea oil rig platform, or it may be on the hundredth floor of a building. The term "surface" can also be used here as an adjective to designate a location of a component or region that is located "at the surface". For example, as used herein, a "surface" computer would be a computer located "on the surface".

The term "downhole" as used herein refers to a place or position deeper than about 16 m depth in the earth. In other words, "downhole" is used in a broad sense to refer to a place that is often not easily or conveniently accessible from a wellhead where people can work. E.g. in a petroleum well, a "downhole" location is often at or near a surface petroleum zone, regardless of whether the production zone is accessed vertically, horizontally, laterally, or at any other angle in between. Also, the term "downhole" is used here as an adjective describing the location of a component or a region. For example, a "downhole" device in a well would be a device located "downhole", as opposed to being located "on the surface".

As used in the present application, "wireless" means the absence of a conventional, insulated wire conductor, e.g. which extends from a downhole facility to the surface. The use of pipe and/or casing as a conductor is considered "wireless".

Likewise, according to conventional terminology of oilfield practice, the descriptions "upper", "lower", "uphole" and "downhole" are relative, referring to distance along the hole depth from the surface, which in deviated or horizontal wells may or may not be in according to vertical elevation measured in relation to a measurement date.

Figure 1 is a diagram showing a petroleum production well 20 according to a preferred embodiment of the present invention. The well 20 has a vertical section 22 and a lateral section 26. The well has a well casing 30 that extends into the wellbore and through a formation 32, and the production pipe 40 extends inside the well casing to transport fluids from downhole to the surface during production. Therefore, the petroleum production well 20 shown in Figure 1 is similar to existing practice in well construction, but with the incorporation of the present invention.

The vertical section 22 of this embodiment includes a gas lift valve 42 and an upper packing 44 to provide favorable lift for the fluid within the tube 40. Alternatively, however, other means of providing artificial lift may be incorporated to form other possible embodiments ( eg rod pumping). Also the vertical part 22 can further vary to form many other possible designs. For example, in an improved form, the vertical portion 22 may comprise one or more electrically controllable gas lift valves, one or more additional induction coils, and/or one or more controllable packings comprising electrically controllable packing valves, as further described in the related applications.

The lateral section 26 of the well 20 extends through a petroleum production zone 48 (eg, oil zone) of the formation 32. The casing 30 in the lateral section 26 is perforated at the production zone 48 to allow fluids from the production zone 48 to flow into the casing . Figure 1 shows only one lateral section 26, but there may be many lateral branches of the well 20. The well configuration typically depends, at least in part, on the layout of the production zone for a given formation.

A portion of the pipe 40 extends into the lateral section 26 and ends with a closed end 52 past the production zone 48. The position of the pipe end 52 inside the casing 30 is maintained by a lateral packing 54, which is a conventional packing. The tube 40 has a perforated section 56 at the production zone 48 for fluid intake from the production zone 48. In other embodiments (not shown), the tube 40 may continue past the production zone 48 (eg, to other production zones), or the tube 40 may terminate with an open end for fluid intake.

An electrically controllable downhole tracer injection device 60 is connected in-line on the pipe 40 inside the lateral section 46, forming part of the production pipe assembly. The injection device is located upstream from the production zone 48 near the vertical section for ease of placement. However, in other embodiments, the injection device 60 may be located further into the lateral section. An advantage of placing the injection device 60 near the pipe inlet 56 at the production zone 48 is that it is a desired location for injecting tracer materials. However, when the injection device is remotely located relative to the pipe inlet 56, as shown in Figure 1, a tracer material can be injected into the pipe inlet 56 at the production zone 48 using a nozzle extension tube 70. The nozzle extension tube 70 thus provides a means of injecting a tracer material into the stream at a location remote from the injection device 60. Ejection of a tracer material at a location remote from (e.g., upstream from) the injection device 60, via the nozzle extension tube 70, allows a sensor adapted to detect a tracer material to be located at or within the injection device 60 (such a sensor 108 as shown in figure 3). In other possible embodiments, the injection device 60 may be adapted to controllably inject a tracer material at a location outside the tubing 40 (eg, directly into the production zone 48, or into an annular space 62 within the casing 30). Therefore, an electrically controlled downhole tracer injection device 60 can be placed at any downhole location within a well where needed.

An electrical circuit is formed using various components of the well 20. Power for the electrical components of the injection device 90 is generated from the surface using the pipe 40 and casing 30 as electrical conductors. Therefore, in a preferred embodiment, the pipe 40 acts as a pipe structure and the casing 30 acts as an electrical return to form an electrical circuit in the well 20. Also, the pipe 40 and the casing 30 are used as electrical conductors for communicating signals between the surface ( e.g., a surface computer system 64) and downhole electrical components within the electrically controllable downhole tracer injection device 60.

In Figure 1, a surface computer system comprises a master modem 66 and a source of time-varying current 68. However, as will be apparent to one of ordinary skill in the art, the surface equipment may vary. A first computer terminal 71 on the surface computer system 64 is electrically connected to the pipe 40 at the surface, and transmits time-varying electrical current into the pipe 40 when power to and/or communication with downhole devices is required. The current source 68 produces the electric current, which carries power and communication signals down the wellbore. The time-varying electrical current is preferably alternating current (AC), but can also be a varying direct current (DC). The communication signals may be generated by the master modem 66 and fed into the stream produced at the source 68. Preferably, the communication signal is a spread spectrum signal, but other forms of modulation or distortion may be used in the alternative.

A first induction coil 74 is placed around the tube in the vertical section 22 below the point where the lateral section 26 extends from the vertical section. Another injection coil 90 is located around the tube 40 within the lateral section 26 near the injection device 60. The induction coils 74, 90 comprise a ferromagnetic material and are not powered. Because the coils 74, 90 are located around the pipe 40, each coil acts as a large inductor to the AC in the well circuit formed by the pipe 40 and the casing 30. As described in more detail in the related applications, the coils 74, 90 function based on their size (mass), geometry, and magnetic properties.

An insulated pipe joint 76 is incorporated at the wellhead to electrically isolate the pipe 40 from the casing 30. The first data terminal 71 from the power source 68 passes through an insulated gasket 77 at the hanger 88 and is electrically connected to the pipe 40 below the insulated pipe joint 76. A second data terminal 72 of the surface data system 64 is electrically connected to the casing 30 on the surface. The insulators 79 of the pipe joint 76 thus prevent a short circuit between the pipe 40 and the casing 30 at the surface. In an alternative to (or in addition to) the insulated pipe joint 76, a third induction coil 176 (see Figure 2A) may be placed around the pipe 40 above the electrical connection point of the first data terminal 71 to the pipe, and/or the hanger 88 may be a insulated hanger 276 (see Figure 2B) having insulators 277 to electrically isolate the pipe 40 from the casing 30.

The lateral gasket 54 at the pipe end 52 inside the lateral section 26 provides an electrical connection between the pipe 40 and the casing 30 downhole past the second coil 90. A lower gasket 78 in the vertical section 22, which is also a conventional gasket, forms an electrical connection between the pipe 40 and the casing 30 downhole below the first induction coil 74. The upper packing 44 of the vertical section 22 has an electrical insulator 79 to prevent an electrical short circuit between the pipe 40 and the casing 30 at the upper packing. Also, various centralization units (not shown) having electrical isolators to prevent short circuits between the pipe 40 and the casing 30 may be included as needed through the well 20. Such electrical isolation of the upper packing 44 or the centralization units may be accomplished in various ways as will be apparent. for someone with ordinary skills in the technique. The upper and lower packings 44, 48 form hydraulic isolation between the main wellbore of the vertical section 22 and the lateral wellbore of the lateral section 26.

Figure 3 is an enlarged view showing a portion of the lateral section 26 of Figure 1 with the electrically controllable downhole tracer injection device 60 therein. The injection device 60 includes a communication and control module 60, a tracer material reservoir 82, an electrically controllable tracer injector 84, and a sensor 108. The components of an electrically controllable downhole tracer injection device 60 are preferably all contained in a single, sealed pipe section 68 together with a module to facilitate handling and installation, as well as to protect the components from the surrounding environment. However, in one embodiment of the present invention, the components of an electrically controllable downhole tracer injection device 60 may be separate (ie, no pipe member 86) or combined in other combinations. A first device terminal 91 of the injection device 60 is electrically connected between the pipe 40 and a source side 94 of the second induction coil 90 and the communication and control module 80. A second device terminal 92 of the injection device 60 is electrically connected between the pipe 40 and an electrical return side 96 of the second induction coil 90 and the communication and control module 80. Although the lateral packing 54 provides an electrical connection between the pipe 40 on the electrical return side 96 of the second induction coil 90 and the casing 30, the electrical connection between the pipe 40 and the well casing 30 can also be achieved in different ways, some of which may be seen in related applications, including (but not limited to): a different packing (conventional or controllable); a leading centralizer; conducting fluid in the annulus between the pipe and the well casing; or combinations of these.

Figure 4 is a simplified electrical diagram illustrating the electrical circuit designed in the well 20 of Figure 1.1 operation, and with reference to both Figure 1 and Figure 4, power and/or communications are sent into the pipe 40 on the surface via a first data terminal 71 below the insulated pipe joint 76. Time-varying current is prevented from flowing from the pipe 40 to the casing 90 via the hanger 88 due to the insulators 79 of the insulated pipe joint 76. However, the time-varying current flows freely along the pipe 40 until the induction coils 74, 90 are encountered. The first inductor 74 provides a large inductance that prevents most of the current from flowing through the tube 40 at the first inductor. Likewise, the second inductor 90 provides a large inductance that discourages most of the current from flowing through the tube 40 at the second inductor. A voltage potential is formed between the pipe 40 and the casing 30 due to the induction coils 74, 90. The voltage potential is also formed between the pipe 40 on the source side 94 of the second induction coil 90 and the pipe 40 on the electrical return side 96 of the second induction coil 90. Because the communication and control module 80 is electrically connected across the voltage potential, most of the current entering the pipe 40 that is not lost along the way is routed through the communication and control module 80, which distributes and/or decodes power and/or communications for the injection device 60. After passing through the injection device 60, the current returns to the surface computer system 64 via the lateral packing 54 and the casing 30. When the current is alternating current, the flow of current as just described will also be reversed through the well 20 along the same path.

Other alternative ways of developing an electrical circuit using a tubular structure of a well and at least one induction coil are described in related applications, many of which may be used in conjunction with the present invention to provide power and/or communications to electrically driven downholes devices and to devise other embodiments of the present invention.

Reference is again made to Figure 3. The communication and control module 80 comprises an individually addressable modem 100, power matching circuit 102, control interface 104, and sensor interface 106. Because the modem 100 in the downhole injection device 60 is individually addressable, more than one downhole device can be installed and operated independently of others .

In Figure 3, the electrically controllable tracer injector 84 is electrically connected to the communication and control module 80, and thus obtains power and/or communications from the surface computer system 64 via the communication and control module 80. The tracer material reservoir 82 is in fluid communication with the tracer material injector 84. The tracer material reservoir 82 is an independent reservoir that stores and supplies tracer materials for injection into the well at the casing injector 84. The tracer material reservoir 82 of Figure 3 is not supplied by a tracer material supply pipe (not shown) extending from the surface, but in other embodiments it may be. Therefore, the size of the tracer material reservoir 82 may vary, depending on the volume of tracer material required for injection into the well 20. The tracer material injector 84 of a preferred embodiment comprises an electric motor 110, a screw mechanism 112, and a nozzle 114. The electric motor 110 is electric connected to and receives movement command signals from the communication and control module 80. The nozzle extension tube 70 extends from the nozzle 114 into the interior 116 of the tube at the tube inlet 56 (further upstream), forming a fluid passageway from the tracer material reservoir 82 to the tube interior 116. The screw mechanism 112 is mechanically coupled to the electric motor 110. The screw mechanism 112 is used to drive tracer materials out of the reservoir 82 and into the tube interior 116, via the nozzle 114 and via the nozzle extension tube 20, in response to a rotational movement of the electric motor 110. Preferably, the electric motor 110 is a stepper engine, and thus delivers spo raw material injection in incremental amounts.

In operation, the fluid flow from the production zone 48 passes around the tracer injection device 60 as it flows through the pipe 40 to the surface. Commands from the surface data system 64 are transmitted downhole and received by the modem 100 by the communication and control module 80. Inside the injection device 60, the commands are decoded and passed from the modem 100 to the control interface 104. The control interface 104 then commands the electric motor 110 to operate and inject the specific quantity of casing materials from the reservoir 82 into the fluid stream into the pipe 40. The tracer injection device 60 then controllably injects a casing material into the fluid stream flowing into the pipe 40 as needed or desired, in response to commands from the surface data system 64 via the communication and control module 80.

The tracer injection device 60 in Figure 3 also includes sensors 108. At least one of the sensors 108 is adapted to detect the presence and/or concentration of a tracer material within the flow passing through the pipe 40. The sensors 108 are electrically connected to the communication and control module 80 via a sensor interface 106. The tracer injection device 60 can also further include sensors to make other measurements, such as flow rate, temperature or pressure. The data from the sensors 108 are encoded into the communication and control module 80, and can be transmitted to the surface data system 64 by modem 100. During operation, when the tracer material is injected into the tube interior 116 upstream at the tracer injector 84 (via the nozzle extension tube 70, the sensors thus detect 108 the tracer material as it passes within the stream By measuring the arrival time (time from injection to detection) and/or the concentration of detected tracer materials, the characteristics of the stream can be determined, as further detailed below.

As will be apparent to one of ordinary skill in the art, the mechanical and electrical arrangement and configuration of components within the electrically controllable tracer injection device 60 may vary while still performing the same function of producing electrically controllable tracer injection downhole. For example, the contents of the communication and control module 80 may be as simple as a wire conductor terminal for distributing electrical connections from the pipe 40, or may be very complex and include (but not limited to) a modem, a rechargeable battery, a power transformer , a microprocessor, a memory storage device, data acquisition board, and motion control board.

Figures 5A through 5D illustrate some possible variations of the tracer material reservoir 82 and the tracer injector 84 that may be included in the present invention to design other possible embodiments. In Figures 5A to 5D, a nozzle extension tube 70 is not incorporated. The tracer injection device shown in figures 5A to 5D is thus adapted to be placed at the place where the tracer injection is desired. However, a nozzle extension tube may also be incorporated in any of the embodiments shown in Figures 5A to 5D.

In Figure 5A, the tracer injector 84 comprises a pressurized gas reservoir 118, a pressure regulator 120, an electrically controllable valve 122, and a nozzle 114. The pressurized gas reservoir 118 is fluidly connected to the reservoir 82 via the pressure regulator 120, thus delivering a generally constant gas pressure to the reservoir. The tracer material reservoir 82 has a bladder 124 within it, which contains lining materials. The pressure regulator 120 regulates the passage of pressurized gas supplied from the pressurized gas reservoir 118 into the reservoir 82, but outside the bladder 124. The pressure regulator 120 can, however, be replaced with an electrically controllable valve. The compressed gas exerts a pressure on the bladder 124, and thus on the tracer material in it. The electrically controllable valve 122 regulates and controls the passage of tracer material through the nozzle 114 and into the tube interior 116. Because the lining materials inside the bladder 124 are pressurized by the gas from the pressurized gas reservoir 118, the tracer materials are forced out of the nozzle 114 when the electrically controllable valve 122 is opened.

In Figure 5B, the tracer material reservoir 82 is divided into two volumes 126, 128 by a bladder 124, which acts as a separator between the two volumes 126, 128. A first volume 126 inside the bladder 124 contains the tracer material, and a second volume 128 inside the tracer material reservoir 82 but outside the bladder, contains a pressurized gas. The reservoir 82 is thus pressurized, and the pressurized gas exerts pressure on the tracer material inside the bladder 124. The tracer injector 84 comprises an electrically controllable valve 122 and a nozzle 114. The electrically controllable valve 122 is electrically connected to and controlled by the communication and control module 80. The electrically controllable valve 122 controllable valve 122 regulates and controls the passage of tracer material through the nozzle 114 and into the tube interior 116. The tracer materials are forced out of the nozzle 114 due to the gas pressure when the electrically controllable valve 122 is opened.

The embodiment shown in Figure 5C is similar to that of Figure 5B, but the pressure on the bladder 124 is provided by a spring member 130. Also in Figure 5, the bladder may not be necessary if there is a movable seal (eg, sealed piston) between the spring member 130 and the tracer material in the reservoir 82. One of ordinary skill in the art will appreciate that there can be many variations in the mechanical design of the tracer injector 84 and the use of spring parts to produce pressure on the tracer material.

In Figure 5D, the tracer material reservoir 82 has a bladder 124 containing a tracer material. The tracer injector 84 comprises a pump 134, a one-way valve 136, a nozzle 114, and an electric motor 110. The pump 134 is driven by the electric motor 110, which is electrically connected to and controlled by the communication and control module 80. The one-way valve 136 prevents backflow into the pump 134 and the bladder 124. The pump 134 drives the tracer materials out of the bladder 124, through the one-way valve 136, out of the nozzle 114, and into the interior of the tube 116. The use of the tracer injector 84 in Figure 5D can thus be advantageous in a case where the tracer material reservoir 82 is randomly shaped to maximize the volume of tracer material held therein for a given configuration because the reservoir configuration is not dependent on the tracer injector 84 configuration implemented.

Thus, as the examples in Figures 5A to 5D illustrate, there are many possible variations of the tracer material reservoir 82 and the tracer injector 84. One of ordinary skill in the art will see that there can be many variations to perform the functions of storing tracer materials downhole in combination with controllable injection of the tracer material into the tube interior 116 in response to. an electrical signal. Variations (not shown) on the tracer injector 84 may further include (but are not limited to): a venturi at the nozzle; pressure on the bladder produced by a turbo device which extracts rotational energy from the fluid flow within the tube; extraction of pressure from other areas of the formation routed via a pipe; any possible combination of the parts of figures SA to SD; or combinations of these.

The tracer injector assembly 60 will not necessarily inject tracer material into the tubing interior 116. In other words, a tracer injection assembly may be adapted to controllably inject a tracer material into the formation 32, into the casing 30, or directly into the production zone 48. A single tracer injector assembly 60 may also be adapted to emit multiple tracer materials (ie, different tracer identifiers or signatures), such as by having multiple tracer material reservoirs 82 and/or multiple tracer injectors 84. A single tracer injector device 60 can be adapted to inject tracer materials into a well at different places, e.g. by having multiple nozzle extension tubes 70 extending to multiple locations.

The tracer injector assembly 60 may further include other components to form other possible embodiments of the present invention, including (but not limited to): other sensors, a modem, a microprocessor, a logic circuit, an electrically controllable tube valve, multiple tracer material reservoirs (which may contain different tracer materials), multiple tracer injectors (which can be used to eject multiple tracer materials to multiple locations), or any combination of these. Tracer materials injected can be solid, liquid, gas or a mixture of these. Tracer materials injected may be a single component, multiple components, or a complex formulation. Furthermore, there may be multiple controllable tracer injection devices for one or more lateral sections, each of which may be independently addressable, addressable groups, or uniformly addressable from the surface computer system 64. As an alternative to being controlled by the surface computer system 64, downhole electrically controllable injection device 60 may be be controlled by electronics in it, or by another downhole device. Likewise, the downhole electrically controllable injection device 60 can control and/or communicate with other downhole devices. In an improved form of an electrically controllable tracer injection device 60, it comprises at least one additional sensor, each adapted to measure a physical quality such as (but not limited to): absolute pressure, differential pressure, fluid density, fluid viscosity, acoustic transmission or reflection properties, temperature , or chemical composition. Also, a tracer injector device 60 will not necessarily contain any sensors (ie, no sensor 108 ), and the sensor 108 for detecting a tracer material may be separately and remotely located (eg, downstream, or on the surface) relative to the tracer injection device 60 .

Figure 6 illustrates an example of a separate, downhole sensor device 140 that has its own corresponding inductor 142 located near it for routing power and/or communications for the sensor device. The sensor device 140 comprises a sensor 108, a communication and control module 144 and a modem 146. Data collected by the sensor device 140 can thus be transferred to a surface data system or other downhole device using the pipe 40 and/or the casing 30 as an electrical conductor.

In yet another method of operation, the tracer can be generated downstream using electrical currents, thereby eliminating the need for a downhole chemical reservoir. This method offers the possibility of an ongoing supply of tracer material throughout the life of the well. For example, changes in the pH of natural seawater can be affected by an electrolytic cell that decomposes the salts into chlorine gas and metal hydroxide. Typically, sodium chloride is decomposed into chlorine gas and metal hydroxide. A pH sensor can be used to detect such a pulse of high pH water that is generated in the line or is collected and released as a mass.

Another potentially useful electrically driven chemical reaction is the generation of ozone as used in devices to control biological activity in swimming pools and water supply systems. In another application, a solid material may be placed in the well and brought to enter the well's fluid system by controlled dissolution achieved by a controlled pulse of electrical energy. The dissolved material is preferably unique to the fluid environment in the well, thus allowing detection at low concentrations. An example of such a solid material is a metallic zinc element. Commercially available analytical devices offer the detection of many other compounds that can be electrically generated by those skilled in the art.

Upon review of related applications, one of ordinary skill in the art can see that there may also be other electrically controllable downhole devices, as well as multiple induction coils, further included in a well to design other possible embodiments of the present invention. Such other electrically controllable downhole devices include (but are not limited to): one or more controllable packings having electrically controllable packing valves, one or more electrically controllable gas lift valves; one or more modems, one or more sensors; a microprocessor; a logic circuit; one or more electrically controllable pipe valves to control the flow from different lateral branches; and other electronic components as required.

In use, a number of applications of the present invention arise, both in conventional wells and in complex future designs. For example, in vertical wells completed over long intervals, the inflow profile of production wells is of interest to correct uneven inflow and thereby allow uniform thinning of the entire formation. Likewise, flooding operations long-interval completions depend on achieving smooth injection profiles to sweep out the entire stage. Figures 7 A and 7B schematically illustrate, respectively, uniform inflow and uniform injection profiles, for a vertical well.

In wells with long horizontal completions, maintenance of uniform profiles is less dependent on differences in permeability of geological layers than it is in pressure gradients along the wells. These pressure gradients tend to accommodate high production rates near the bottom of the well (ie, the horizontal section closest to the vertical part of the well). Figures 7C and 7C schematically illustrate uniform inflow and injection profile, for a long horizontal completion.

Another application is the use of the tracer material to differentiate production in wells with several lateral branches. In these wells it is important to understand which lateral is producing too much water or which lateral has already been emptied. Figure 7E schematically illustrates a uniform inflow profile for several laterals. Figures 7A to 7E thus illustrate the desirable flow profiles for just a few of the many possible well configurations, which are highly dependent on the natural layout of production zones in a given formation.

The movement of fluids in a subsurface well can be monitored by injecting tracer materials at various positions and observing the time of arrival and discharge from fluids that entered the well downstream from the tracer injection point. As described above, the tracer materials are injected in a stream from a storage reservoir 82 within an injection device 60. Alternatively, however, a tracer material may be generated within the injection device 60 by electrical methods.

The movement of a shock of tracer material injected into a well's stream is dependent on the degree of mixing during transport along the well. In the case of a single flow in a pipe, the velocity profile varies with the radial position, so that the fluid moves somewhat faster at the center of the pipe than at the wall. If the flow is in the laminar region (ie, at low rates) the shape of the velocity profile is parabolic, and in the case of no-slip at the wall, a tracer material would be dispersed along the length of the flow. In practice, because the pipe walls are rough and the flow is fast, turbulent flow will usually occur. The turbulence mixes the fluids so that the tracer materials are more evenly transported and generally reflects the average velocity of the flow in the pipe.

In production or injection wells completed with perforated or shielded casing, fluid flows through the pipe wall into the flow along the wall. In this case, a flow of a fluid that enters the well at the wall at different positions along the open interval more complicated. Examples given below relate to flow in either vertical or horizontal wells, however, a vertical well is used to demonstrate a case of laminar flow in which the inflow occurs along an open interval.

Assuming that the flow is laminar and no mixing occurs across the streamlines, the fluid entering the bottom of the open interval will initially fill the entire cross-section of the hole. Further downhole, further inflow of fluid will restrict the original fluid that entered at the bottom, driving it radially inward. At the top of an open interval, the last fluid to enter will be in the radial region near the wall, and the first fluid to enter at the bottom will be at the center of the well. Tracer sensors could thus be placed so that they meet the tracer materials in the passing stream. The use of a turbulator (not shown) immediately upstream of the sensor to mix the liner material flow into the main flow can be advantageous for this purpose.

Reference is again made to Figure 7A, which illustrates flow patterns for a fluid flowing at a uniform rate into a circular pipe, where this flow pattern can be constructed with the following model:

Assumptions:

1) Uniform inflow of fluids into the well; and

2) Uniform velocity profile inside the well.

These assumptions are somewhat opposite to what is expected in parabolic velocity profiles for flow in a tube with no leakage at the walls. However, in this case where the fluids enter at the wall, the flow will more closely approximate an impingement flow.

Definitions:

q = inflow rate/unit length of interval [bbl/day/ft]

L = height above bottom of open interval [ft]

Lj = fluid (tracking) inflow point above the bottom of the open

interval [feet]

L0 = total height above open interval [ft]

f = fraction of well area occupied by the flow from an internal flow

from 0 to L

v = velocity of flow at height L [ft/day]

r0 = radius of the well [ft]

r = radius of the flow of fluid into the well that entered below L

[foot]

Now consider the fluid entering the well at a height, Li9 above the bottom of the well. At elevations above this elevation (L equal to or greater than Lj), the fraction of the cross-sectional area of the well occupied by the fluid that entered below Lj is:

The plot in Figure 8 shows the streamlines for the flow in a well when the fluid enters the well evenly with depth. When the flow is turbulent, as is the case in most wells, the streamlines are mixed. Under these conditions, the plot on figure 8 represents the fraction of the flow at a given depth (rather than the radial position) that consists of fluids entering the well below this depth.

In order to derive information about the fluid movement in wells, it is necessary to understand the arrival time and concentration of tracer materials that may be injected at different positions in the fluid stream. Use of the present invention provides ways to controllably inject a tracer material at virtually any downhole location and/or to detect the presence or concentration of tracer material within the flow for virtually any downhole location. Figures 9A to 9J give just a few examples of the many possible locations of tracer injection devices 60 (which may or may not include a sensor 108) and/or sensor devices 140 in a production or injection well. Again, the desirable configuration of a well typically depends on the layout of the production zones 48 in a formation 32. The downhole tracer injection device 60 and the downhole sensor device 140 may or may not be permanently installed. Permanent downhole devices are preferred because of the cost and time required to add, remove, modify, clean or replace downhole devices. The present invention makes it possible to install a downhole device permanently because, among other things, the present invention provides new methods of bringing power and/or communications to such a permanent downhole device. Figure 9 is a simplified diagram illustrating a possible configuration of the present invention in a vertical production well. In Figure 9A, there are five downhole casing injection devices (Ti-T5) 60 located at various locations along the depth of the vertical well at production zone 48 to inject tracer materials into the fluid stream at various depths. The downhole sensor device 140 is located upstream of the tracer injection devices (Ti-T5) 60 to detect tracer materials in the stream as it passes. The sensor device 140 may comprise several sensors 180, each of which is adapted to detect a different tracer material signature corresponding to the different tracer injection devices (IVT5) 60. Alternatively, the same tracer material may be used in all injection devices, and the origin of the tracer pulse determined by selecting the injector device individually. A tracer material ejected from the central tracer injection device (T3) 60 and detected by the sensor device 140 thus provides information about the flow entering the production pipe 40 at the central tracer injection device (T3) 60. The downhole sensor device 140 can also be located on the surface. But it may be more desirable in some cases to have the downhole sensor device 140 placed closer to the tracer injection point so that the tracer material is less diluted by the fluids in the flowing stream. Figure 9B is a simplified diagram illustrating another possible configuration of the present invention in a vertical production well. In Figure 9B, there are five downhole tracer injection devices (TrT5) 60 located at various locations along the depth of the vertical well at the production zone 48 to inject tracer materials into the stream at various depths. However, instead of having one sensor device 140 as shown in Figure 9A, in Figure 9B there are five separate, downhole sensor devices (S1-S5) 140 at different locations along the depth of the vertical well. Each sensor device (Sp S5) corresponds to a tracer injection device (TrT5) 60. The sensor device S4 thus comprises a sensor 108 adapted to detect tracer material issued from the tracer injection device T4. In such a configuration, a sensor device 140 co-located with a tracer material injection device 60 (e.g., sensor device S2 and tracer injection device T3) may be electrically connected to each other, may be electrically connected across the same induction coil, may operate from the same communication and control module, may share the same modem, and/or may be included within the same house.

Figure 9C is a simplified diagram illustrating a possible configuration of the present invention in a vertical injection well. In Figure 9C, six sensor devices (SpSe) 140 are 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 tracer materials at the surface because most or all of the flow has its origin from the surface. However, it is still possible to have one or more casing injection devices 60 at various locations downhole in addition to or instead of the tracer injection device 60 at the surface.

The configurations of Figures 9A through 9C may be combined such that the placement of tracer injection devices 60 and sensor devices 140 provides tracer detection and controllable tracer injection for use during both the production and production petroleum injection stages of a well. The well can thus switch from a production stage to an injection stage (and vice versa) without the need to reconfigure the tracer injection device 160 and the sensor device 40 downhole in the well. The tracer injection device 60 and the sensor device 140 can therefore be permanently installed for long-term use and for multiple users. Figure 9D is a simplified diagram illustrating a possible configuration of the present invention in a production well having a horizontal completion. In Figure 9D, there are seven downhole tracer injection devices (TpT7) 60 located at different locations along the horizontal section at the production zone 48 to inject tracer materials into the stream at different locations. As in Figure 9A, a downhole sensor device 140 is located upstream of the tracer injection device (T1-T7) 60 to detect tracer materials in the stream as it passes. Figure 9E is a simplified diagram illustrating another possible configuration of the present invention in a production well having a horizontal completion. The configuration of Figure 9E is the same as the configuration of Figure 9B, except that a sensor or sensors 108 for detecting the tracer materials is located on the surface. The sensor 108 can be a stand-alone sensor device 140, or can be part of a surface data system 64. Figure 9F is a simplified diagram illustrating yet another possible configuration of the present invention in a production well that has a horizontal completion. The configuration of Figure 9F is similar to the configuration of Figure 9B in that there are three more sensor devices (Si-S7) 140 corresponding to the multiple tracer injection devices (Ti-T7) 60. Figure 9G is a simplified diagram illustrating a possible configuration of the present invention in a injection well that has a horizontal section. The configuration of Figure 9G is similar to the configuration of Figure 9C in that it has multiple downhole sensor devices (SpS7) 140 adapted to detect tracer material injected into the well at the surface by the tracer injection device 60. In an alternative, the tracer injection device 60 may be located down the wellbore. Figure 9H is a simplified diagram illustrating a possible configuration of the present invention in a production well having multiple lateral completions. In Figure 9H, there are tracer injection devices (Ti-T4) 60 inside the lateral branches, each tracer injection device 60 being near the connection point between a lateral branch and the main borehole. Such placement of the tracer injection device (T1-T4) 60 has the advantage of facilitating installation (compared to installing a device further down the borehole within a lateral branch). A sensor device 140 is located upstream from the top lateral branch. The sensor device 140 is adapted to detect tracer materials injected into the lateral branches by the tracer injection devices (TrT4) 60. The sensor device 40 can thus comprise multiple sensors 108 adapted to detect multiple tracer material signatures. Alternatively, the sensor devices 140 or the sensor 180 may be located at the surface, but the downhole location shown in Figure 9H is often more preferable. Figure 91 is a simplified diagram illustrating another possible configuration of the present invention in a production well having multiple lateral completions. In Figure 91, as in Figure 9H, there are tracer injection devices (Tr T4) 60 shortly inside the lateral branches. But in Figure 91, there are four sensor devices (SpS4) 140, one for each tracer injection device (Ti-T4) 60. The sensor device S3 is thus adapted to detect a tracer material injected into the flow by a tracer injection device T3, which produces flow information regarding the lateral branch which has the tracer injection device T3 in it. Because the sensor devices S3 and S4 are located in the same location, they can be combined into a single sensor device 140 that has multiple sensors 108. Figure 9J is a simplified diagram illustrating yet another possible configuration of the present invention in a production well that has several laterals

completions. In Figure 9J, the tracer injection devices (T2-T4) 60 are located within the lateral branches near the production zone 48 and the tracer injection device (Ti) 60 is located within the vertical portion below the lateral branches. Sensor devices (S2-S4) 140 are located upstream from the tracer injection devices (T2-T4) 60, within the laterals near the vertical section. A sensor device (Si) is placed upstream from the tracer device (Ti) and below the lateral branches. The flow in each section of the well can thus be independently monitored.

For the configurations illustrated in Figures 9A to 9J, there are multiple tracer injection devices 60 and/or multiple sensor devices 140, the tracer injection devices 60 and/or the sensor devices 140 may be spaced at equally spaced intervals. However, the several tracer injection devices 60 and/or sensor devices 140 may also be randomly separated from each other or by any other spacing device. Furthermore, each of the multiple tracer injection devices 60 and/or sensor devices 140 may have its own induction coil to provide power and/or communication, or some or all of the tracer injection devices 60 and/or sensor devices 140 may share an induction coil. Because the tracer injection devices 60 and the sensor devices 140 can be independently addressable and independently controlled, one or more well sections can be independently monitored.

Below are several calculations to illustrate how information or measurements obtained using the present invention can be used to determine fluid movement or flow characteristics of a well during production or injection. The calculations shown below are based on fluid inflow into a production well. With slight modifications, however, injection well profiles can also be used in which tracer is injected at a location at the top of the interval, and the arrival time is observed at separate monitors along the open interval.

Definitions:

Axj = the thickness of the layer in [feet]

h = total thickness of interval [ft]

ij = inflow rate into the well per unit length from the layer in [barrels/day/ft] qi = ijAxj = flow rate into the well from the layer in [barrels/day]

qr = Eqi = total flow rate into the well [barrel/day]

Qi = flow rate inside the well at the depths of the layer in [barrels/day] Qt = total flow rate out of the well = qT [barrels/day]

n = interval number (counted from top to bottom)

N = total number of intervals

vp = volume of injected tracer pulse [cc]

Cp = concentration of trace material in injected pulse [g/cc]

vpCp = mass of tracer material injected [g]

r = radius of well [ft]

tj = transit time over layer i

Assumptions:

Case 1 Steady inflow

The flow quantity in the well at layer i is the sum of the inflow quantity in all layers below, and in layer i:

The transit time over the layer i is:

Total transit time from the inflow from layer k to the top of the interval is:

An example calculation for four layers with a constant inflow rate is given below. Beginning at the bottom of the interval, the amount of flow inside the well increases as each layer successively feeds into the well (see Table 1, column 2). A case in which the thickness of the layers is equal, the well volume opposite each layer is equal. Therefore, the transit time for fluids in the well above the layer is inversely proportional to the amount of flow in the well (see table 1, column 3). Summing these layer transit times from the top down to a layer in which a tracer material is injected into the stream gives the total transit time for a tracer to arrive at the top of the production interval (see Table 1, column 4). Injected tracer is diluted by inflowing fluids that enter above the tracer injection point. The concentration of the tracer material that arrives at the top of the interval in relation to the first injected concentration can be calculated by dividing the flow rate in the well at the injection point by the flow rate at the top of the interval, i.e. by the total flow rate (see table 1, column 5).

Figure 10 illustrates the relative arrival times at the top of the interval for fluids entering the well at 100 locations along the interval. Figure 11 illustrates the relative arrival times at the top of the interval for fluids entering the well at 1000 locations along the interval.

Case II Variable inflow / variable layer thickness.

For this more complex case, the flow rate of fluid entering the vertical well from a layer is a function of the permeability ratio (k) of the thickness (Ayj) and the normalized inflow rate determined by the pressure gradient.

where

ij = constant [barrels/day/ft]

Again, the flow rate in the well at layer is the sum of the inflow rates in all the layers below, and in the layer in:

Where the inflow is summed from the bottom up to layer i, the transit time over layer i is:

The total transit time of fluid in the well from the inflow at layer i to the top of the interval is: (The transit times are summed from layer 1 at the top of the interval down to layer i)

Wells with multiple lateral horizontal completions

When wells are completed with several lateral horizontal branches, as in Figures 9H-9J, the individual branches cannot be determined by conventional logging or profile measurements. Information and the productivity of individual laterals would be useful in reservoir management that could lead to overwork or infill wells in the direction of poorly completed laterals. Likewise, if production from a well, as observed at the surface, shows a sudden increase in water or gas, it is helpful to determine which lateral is causing the problem. In the simplest application of the use of tracers for lateral well diagnostics, the tracer injection point can be located a short distance into the lateral by any of the methods and locations discussed above (see Figures 9H and 91). The detectors can be placed in the vertical section of the well above the top lateral. Laterals that have low productivity will show a long, diluted tracer response, because the transit time of the lateral is long compared to that of the vertical pipe.

Injection wells with long vertical open intervals

In formations that have been flooded over long intervals, maintaining consistent injection profiles is essential to ensure efficient outflow of the entire oil-bearing zone. In a typical injection well completion, fluid is injected through tubing under a packing and allowed to enter the objective zone through perforations in the casing or through a shielded casing. In this application, a number of detectors may be installed along the casing or lining, or preferably along a perforated extension of the pipe below the packing (see Figure 9C). With this configuration, the tracer can be injected at the surface, and the arrival time at the various detectors used to determine the injectivity profile. With the surface readout of the detectors, a complete history of the fluid injection profile through the flooded zone can be obtained. In the case of an injection well, special care must be taken to thoroughly mix the injected tracer material to avoid segregated flow near the wall of the pipe. The reason for this is that the fluid leaves the well at the wall; therefore, tracer material that stays close to the wall will come out of the well in the upper layer, and will not be available for measurement in the lower zones.

An example is given below to demonstrate how tracer arrival times observed at widely spaced monitors can be used to calculate the injection profile in a heterogeneous interval consisting of zones that have widely varying permeabilities.

Example water injection well:

Diameter d = 6 inches

Well completion: 101 feet of unperforated pipe below a seal;

500 feet of perforated interval;

Total injection rate: 800 barrels per day

Injectivity profile: See Figure 1

Time in minutes for the trace to move from one location to the next is:

Therefore, the time for the trace to move from the injection point to the top of the open interval is:

Subsequently, the rate in the well will decrease as the water leaves the perforated interval. Using very short intervals (Ayi = 1 ft), the inverse velocity or transit time (Atj) can be calculated for each depth:

For the first 100 feet, the injectivity is 1 b/d/ft,

At, = (50.355)(1) / (800+799)/2 = 0.062983 min

At2 = (50.355)(1) / (799+798)/2 = 0.063062 min

At10o = (50.355)(1) / (701+700)/2 = 0.071884 min

For the second 100 feet, the injectivity is 4 b/d/ft,

Atioi = (50.355)(1) / (700+696)/2 = 0.072142 min

At2oo = (50.355)(1) / (304+300)/2 = 0.166738 min

For the third 100 feet, the injectivity is 0 b/d/ft,

At2oi = (50.355)(1) / (300+300)/2 = 0.16785 min

Ataoo = (50.355)(1) / (300+300)/2 = 0.16785 min

For the fourth 100 feet, the injectivity is 1 b/d/ft,

At3oi = (50.355)(1) / (300+299)/2 = 0.16813 min

Attoo = (50.355)0) / (201+200)/2 = 0.25114 min

For the fifth 100 feet, the injectivity is 2 b/d/ft,

Atjoi = (50.355)(1) / (200+198)/2 = 0.25304 min

A1500 = (50.355)(1) / (2+0)/2 = 50.335 min

Figure 13 shows these calculations close to the real flow rates that would be observed in a well with the injection profile given above. Figure 14 shows the cumulative sum of all interval times:

and we note that the only change in arrival time is seen in this display even though the injectivities vary from 0 to 4 b/d/ft.

The number of monitoring points is limited by practical assessments. If the tracer monitoring modules are separated by 100-foot intervals, the arrival times for these positions can be used to calculate the injection rates as a function of depth as follows: Knowing the flow rate injected into the well and the arrival times of the tracer material at the top of the open interval and 50 feet down, can one calculate the rate in the well at this depth (Q50),

Using the calculated rate and arrival times of the tracer material at that depth, one can solve for the flow rate (Q100) at the next monitor from the arrival time at that depth (100 feet).

Successively, one calculates the flow rate at each monitor down to the bottom of the interval.

Figure 15 compares the actual flow rate with values calculated from the 50 foot readings. The correspondence is good, with the exception of the bottom location where the flow rate goes to zero and the transit time becomes infinite.

This method for calculating flow quantities can also be used over larger distances.

However, when the fraction of total flow entering the formation in the interval between two monitors is large compared to that passing the upper monitor, significant errors are introduced. For example, if 100 ft spacing is used in the above calculation, the predicted flow rate is too low in Zone II where the true well flow rate decreases from 700 b/d to 300 b/d, as shown in Figure 15. The reason for this discrepancy is the use of the interval average flow rate to adjust the interval transit time.

If the transit time of the zone (Atj) is fitted to a series of Ns transits of subzones, each of which reflects an equal loss of fluid into the formation, a corrected flow rate at the bottom of the zone (Qn) is obtained as follows:

The transit time for the zone (Ati) is known from arrival time observations at the top and bottom of the zone. The sub-zone thickness (Ay„) is equal to the thickness of the zone divided by the number of sub-zones selected (Ns). The well's flow rate at the top of the zone (Q0) is obtained from the calculated value of flow rates at the base of the previous zone. The flow rate at the bottom of the present zone (QN) is obtained by iteration, since an explicit solution of QN in equation 21 is not available.

Production wells with long vertical open intervals

Inflow profiles of long-interval vertical production wells can be analyzed by a method similar to that described above. However, there are some differences that need to be taken into account. In an injection well, the tracer material can be injected at a single point at the surface into the flow moving at maximum velocity (see Figure 9C). The tracer material will pass along the well at decreasing speed. The only part of the well that is not suitable for tracer arrival is the bottom section itself where the flow rate becomes negligible. In the case of a production well, the tracer material must be injected below the interval being analyzed (see Figures 9A and 9B). Near the bottom, the flow rate will be small, and the concentration of the tracer material will be continuously diluted by inflow from the formation as the tracer material moves upward. In practical applications, the arrival times of the tracer material injected near the bottom will be too long and its concentration will be too long to obtain useful information in the upper part of the formation. A less complete definition of productivity profile can be achieved by using pairs of tracer injection modules with detection modules.

In contrast to injection wells where the tracer material moves radially outward as the flow moves down the hole, production wells exhibit a radially inward movement as the produced fluid moves up the hole. If mixing does not occur, a tracer material injected at the wall will later occupy the center of the well as it moves up through the well. This means that there is no danger of the tracer material coming out of the well, but care must be taken at the detection point to avoid missing the passage of the tracer when the detector is placed by the wall. A possible solution is the use of turbulators in the well, placed immediately below the detectors to ensure that the tracer agent passes by the wall.

The analyzes above assume a dominant phase flowing in the well, which can be observed by a single trace. In practice, most production wells have combinations of oil, water and gas flowing in the well. Under these conditions, buoyancy forces can result in rapid transport of phases compared to the average fluid velocity. A wide variety of downhole conditions exist in commercial oil and gas wells, and many options are available for the use of downhole detectors for specific production conditions. These conditions would be obvious to those skilled in the art.

An example of useful information that could be obtained from such devices is the location of entry points for water or gas. In water flooding, there is often a difference in the salinity of the original formation water and the injected flood water. Arrival of fresh water at the surface of an individual well during a waterflood has been used for many years to monitor breakthrough. In long interval wells, however, there is no easy way to distinguish the specific zone in the vertical section that has broken through. Permanently mounted detectors located along the open interval can be used to monitor the progression of a flood and provide guidelines for relief efforts to exclude water breakthrough.

An example calculation is provided below to demonstrate how arrival times of produced fluids at the top of an interval can be used to infer productivity profiles as a function of depth. Equations 3 to 12 given above are used in this calculation.

Example vertical production well:

Figure 16 shows the cumulative inflow of fluids as a function of depth for these four profiles. Figure 17 compares the arrival times for the cases with maps 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 non-uniform. At each of these profiles, the total dimensionless flow rate is 1.0. For uniform inflow, the rate per unit depth is IX. When the entire flow is in the upper half, at a rate of 2X (map A), no transport of fluid will occur in the lower half and the arrival time will be infinite for fluid entering the midpoint of the interval. When the entire inflow is in the lower half at a rate of 2X (map B), the arrival times are short throughout the interval. When the flow rate occurs only in the lower and upper 10% of the interval at 5X (map C), the transit times for fluid from the bottom are faster than for the uniform case, and then become slower than the uniform case for fluid entering near the top. Figure 18 shows that the shapes of the relative arrival times are distinctive for different profiles, and thus the productivity profile can be calculated using a number of tracer injection points separated along the interval (see Figures 9A and 9B).

In addition to the arrival times, the concentrations of a burst of tracer material arriving at the top of the interval from sites along the open interval can be used to verify the interpretation of a productivity profile. Dilution of a tracer shock by the entire inflow of fluid above the tracer injection point is assumed, as calculated in column 5 of table 1.

Figures 19, 20, 21 and 22 show tracer material concentrations and arrival times at the top of the formation for four profiles.

Production wells with long horizontal open intervals

Unlike vertical wells with long completions, wells with long horizontal completions are usually completed in a single geological layer, and therefore their productivity profiles are less dependent on differences in layer permeabilities. In these wells, maintaining uniform profiles is equally important. However, the pressure gradient along the open interval tends to result in higher production rates at the heel than at the toe of the well because greater pressure drawdown can be achieved near the vertical section (the heel). High production rates in parts of the open interval can lead to early gas conning from above the oil-producing elevation, or water coning from below it. Casing monitoring, with separate devices in the horizontal region (see Figures 9D to 9G), would be useful in providing information for proper control of inflow in these wells.

The magnitude of the high productivity at the well can be examined by calculating the effect of distributed inflow of fluid from the formation on the pressure drop along the well. The first calculation will illustrate this effect.

Example horizontal well analysis:

L = length of fully open interval [feet]

N = number of monitoring points (subsections)

AL = L/N = separation of monitors [feet]

n = index of subsection on (from toe to heel)

QN = total flow rate from the well [b/d]

Pn = total pressure drop across open interval [psi]

Ph = pressure loss from flow in the well [(psi/ft) / (w/d)]

dqf = specific inflow quantity with a uniform profile from the formation in

in the well [w/d/ft]

Aqf = inflow amount from the formation to a subsection of the well

[b/d]

Aqn = flow rate in the well at a subsection (n) [b/d]

Apn = pressure drop in subsection n = pH(AL)( Aqn) [psi]

Assume that the well is divided into N well sections, from upstream (toe to full),

With uniform inflow, The flow rate in the well cumulates when the inflow occurs from toe to full, The pressure drop in each subsection is assumed to be proportional to the flow rate, therefore,

Adding the pressure drops in each subsection, the total pressure drop in the well from the toe to the subsequent downstream subsections

Assumptions:

Length of entire open interval = 2,500 feet

Separation of monitors = 100 feet

Total flow rate from the well = 2500 b/d

Specific pressure loss in the well = 10"<4>psi/w/d/ft

Inflow at the toe of a well, no inflow along the interval

(1) For a well in which all 2,500 barrels flow through 2,500 feet of the well, the pressure drop will be:

Uniform inflow

(2) For a well producing uniformly along 25 subdivisions (controllable well sections), the total pressure drop in its open interval, as calculated by Equation 26:

Inflow dependent on reservoir pressure

The inflow rate in the well is proportional to the difference between the reservoir pressure and the pressure in the well. Because the pressure in the well along the open interval depends on the flow rate, the inflow profile must be obtained by an iterative calculation. We define the reservoir pressure (pres) as pressure (p0) above the highest pressure in the well, i.e. the pressure at the toe.

The pressure difference between the reservoir pressure and the pressure in the well at locations downstream from the toe is:

In the first iteration, the cumulative flow and the cumulative pressure drop along the pipe can be calculated by summing up the inflow differential pressure (p0 + p„) and normalizing the subsection differential pressure by that sum:

The inflow rate for each subsection is proportional to the normalized differential pressure, therefore the inflow rate for each subsection is:

The cumulative flow occurring in the well is: and the cumulative pressure drop in the well from the toe to the heel is:

Another iteration is done substituting these values for pressure drop into equation 31. Convergence is fast, in this case only a few iterations are necessary. These can be performed by substituting successive values of pni,2,3... etc. into equation 34. Figure 23 presents the results of these pressure drop calculations for several inflow conditions. When the entire inflow entering the well at the toe, (case 1 - open end pipe), the cumulative pressure drop along the pipe is large, since each section of the pipe undergoes a maximum pressure drop. When the flow is uniform along the length of the horizontal well section, (case 2 - uniform inflow), there is less pressure drop near the toe where the flow rates in the well are low. For the same total flow rate of 2500 b/d, the uniform inflow case results in only about half the total pressure drop (325 psi) compared to Case 1, where the total pressure drop is 625 psi. When the inflow depends on the reservoir pressure (case 3 - non-uniform inflow), an even lower pressure drop occurs. If the reservoir pressure is only slightly higher than the toe pressure of the well, and the pressure drop in the well is large in comparison, most of the inflow will occur at the heal. The lower limit occurs when the reservoir pressure is equal to the well toe pressure (ie p0 = 0). In this case, the total pressure drop is 125 psi. The upper limit, when the reservoir pressure becomes large (p0 = T) results in uniform inflow. Figure 24 shows the calculated flow rates that result from different reservoir inlet conditions. The flow rate that occurs along the horizontal well section under the conditions given above can be normalized in relation to flow rates in a well with uniform inflow.

Therefore, using the present invention and the calculations provided herein, the flows in a production or injection well can be monitored and characterized in real time as necessary. Information generated through the use of the present invention can generate more knowledge of the events that occur downhole and can be used to guide operators or computer systems in changing the production or injection procedures to optimize operations. Such areas of use can greatly influence the efficiency and maximize petroleum production from a given formation. The present invention can also be used for other types of wells (other than petroleum wells), such as a water production well.

Those skilled in the art will appreciate, having the benefit of this disclosure, that the invention provides a petroleum production well having at least one electrically controllable tracer injection device, as well as methods for utilizing such devices to monitor the well's production. It must be understood that the drawings and the detailed description must be understood in an illustrative and not restrictive manner, and are not intended to limit the invention to the particular forms and examples described. On the contrary, the invention embraces any other modifications, changes, rearrangements, substitutions, alternatives, design choices, and embodiments which are obvious to those of ordinary skill in the art, without departing from the spirit and scope of the invention as defined in the claims. It is thus intended that the following requirements shall be interpreted to include all such further modifications, changes, rearrangements, replacements, alternatives, design choices and executions.

Claims (29)

1. A tracer injection system for use in a well (20) comprising a current impedance device (74,90,142) designed for placement around a portion of a pipe structure (40,96) in said well and to counteract a time-varying electrical signal transmitted along the said part of the pipe structure (40,96), characterized by further comprising a downhole, electrically controllable, tracer injection device (60) adapted to be electrically connected to the said pipe structure (40,96) adapted to be driven by the said time-varying electric signal, and adapted to eject a tracer material into said well (20). 2. Tracer injection system according to claim 1, characterized in that the said current impedance device (74,90,142) has a generally ring-shaped geometry and comprises a ferromagnetic material. 3. Tracer injection system according to claim 1, characterized in that the pipe structure (40,96) comprises at least an area of a production pipe (40,96) from the said well, and that the said electrical return comprises at least an area of the said well's (20) casing (30). 4. Tracer injection system according to claim 1, characterized in that the said pipe structure comprises at least an area of a well casing (30). 5. Tracer injection system according to claim 1, characterized in that the injection device (60) comprises an electric motor and a communication and control module (80), where the said electric motor (110) is electrically connected to and adapted to be controlled by the said communication - and control module (80). 6. Tracer injection system according to claim 1, characterized in that the aforementioned injection device comprises an electrically controllable valve (122) and a communication and control module (80), where the electrically controllable valve (122) is electrically connected to and adapted to be controlled by the said communication and control module (80). 7. Tracer injection system according to claim 1, characterized in that said injection device (60) comprises a tracer material reservoir (82) and a tracer injector (84), where said tracer injector material reservoir (82) is in fluid connection with the tracer injector (84), and said tracer injector ( 84) is adapted to eject from the injection device (60) said tracer material from within the tracer material reservoir (82) in response to an electrical signal. 8. Tracer injection system according to claim 1, characterized in that the electrical signal is a power signal. 9. Tracer injection system according to claim 1, characterized in that the electrical signal is a communication signal to control the operation of the mentioned tracer injection device (60). 10. Tracer injection system according to claim 1, characterized in that it further comprises a sensor (108) adapted to detect the tracer material when said tracer material (108) passes the sensor in a flow stream. 11. Tracer injection system according to claim 1, characterized in that it further comprises a nozzle extension pipe (70) which extends from the mentioned tracer injection device (60). 12. A petroleum well for producing petroleum products which is equipped with an injection system according to claim 1, comprising: a pipe structure (40,96) placed inside the borehole for the well (20); a current impedance device (70,90,142) positioned around the pipe structure (40,96) to define an electrically conductive portion of said pipe structure; a source of time-varying signal electrically connected to the electrically conductive part of the pipe structure (40,96); characterized in that the system further comprises: an electrically controllable tracer injection device (60) according to claim 1 electrically connected to the conducting part and adapted for connection to the said time-varying signal. 13. Petroleum well according to claim 12, characterized in that said current impedance device (74,90,142) comprises a non-driven induction coil comprising a ferromagnetic material so that said induction coil functions based on its size, geometry, spatial relationship to the pipe structure (40,96), and magnetic properties. 14. Petroleum well according to claim 12, characterized in that the said pipe structure (40,96) comprises a production pipe (40,96) and a well casing pipe (30), where the said time-varying signal is supplied to at least one of the said pipes (40, 96) and casing (30). 15. Petroleum well according to claim 12, characterized in that said tracer injection device (60) comprises an electrically controllable valve (122). 16. Petroleum well according to claim 12, characterized in that the tracer injection device comprises an electric motor (110). 17. Petroleum well according to claim 12, characterized in that the said tracer injection device comprises a modem (100). 18. Petroleum well according to claim 12, characterized in that said tracer injection device comprises a tracer material reservoir (82). 19. Petroleum well according to claim 12, characterized in that it further comprises a sensor (108) adapted to detect trace material. 20. Petroleum well according to claim 12, characterized in that it further comprises a nozzle extension pipe (70) which extends from the tracer injection device (60). 21. Petroleum well for producing petroleum products according to claim 12 comprising: a well casing (30) extending into a wellbore of said well (20); a production pipe (40,96) extending within the casing (30); a source of time-varying electric current (68) located on the surface, the current source being electrically connected to, and adapted to output a time-varying current into, at least one of said pipes (40,96) and casing (30); characterized in that the well further comprises: a downhole tracer injection device (60) according to claim 1 comprising a communication and control module (80), a tracer material reservoir (82), and an electrically controllable tracer injector (84), where the said communication and control module (80 ) is electrically connected to at least one of said pipes (40,96) and casing (30), and the tracer injection device (60) is electrically connected to said communication and control module (80), and said tracer material reservoir (82) is in fluidic communication with the tracer injector (60); a downhole current impedance device (70,90,142) which is placed around a part of at least one of said pipes (40,96) and casing (30), and where said current impedance device is adapted to route a part of said electric current through the communication and control module (80). 22. Petroleum well according to claim 21, characterized in that it comprises a sensor device electrically connected to at least one of said pipes (40,96) and casing (30), where said sensor device comprises a sensor (108) adapted to detect a tracer material in a flow stream in the aforementioned well (120). 23. Petroleum well according to claim 21, characterized in that it further comprises a nozzle extension pipe (70) which extends from the mentioned tracer injector (60). 24. Petroleum well according to claim 21, characterized in that said tracer injector (60) comprises an electric motor (110), a screw mechanism (112), a nozzle (114), where said electric motor (110) is electrically connected to communication and the control module (80), the screw mechanism (112) is mechanically coupled to said electric motor (110), said nozzle (114) extends into an interior of the tube (40,96), where said nozzle (114) forms a fluid passage between said tracer material reservoir (82) and the interior of the pipe, and said screw mechanism (112) is adapted to drive the tracer material out of the tracer material reservoir (82) and into the interior of the pipe via said nozzle (114) in response to a rotational movement of the electric motor (110). 25. Petroleum well according to claim 21, characterized in that said tracer material reservoir (82) comprises a separator (124) which divides an interior of the tracer material reservoir (82) into two volumes, and where said tracer injector comprises an electrically controllable valve (122) and a nozzle (114), where a first of said reservoir internal volumes contains a tracer material, another of said reservoir internal volumes (118) contains a pressurized gas so that said gas exerts a pressure on the tracer material in the first volume (124), where the electrically controllable valve (122) is electrically connected to and controlled by said communication and control module (80), and the first volume (124) is connected to an interior of the pipe via said electrically controllable valve (122) and via the aforementioned nozzle (114). 26. Petroleum well according to claim 21, characterized in that said tracer material reservoir (82) comprises a separator (124) which divides an interior of the tracer material reservoir into two volumes, and where said tracer pipe injector comprises an electrically controllable valve (122) and a nozzle (114) ), where the first of the aforementioned reservoir internal volumes (124) contains a tracer material, a second of the reservoir's internal volumes contains a spring part (130) so that the spring part (130) exerts pressure on the tracer material in the first volume, and an electrically controllable valve (122) which is electrically connected to and controlled by the aforementioned communication and control module (80), and the first volume (124) is in fluid communication with an interior of the aforementioned tube (40,96) via the aforementioned electrically controllable valve ( 122) and via the aforementioned nozzle (114). 27. Petroleum well according to claim 21, characterized in that the said current impedance device (70,90,142) comprises a non-driven induction coil comprising a ferromagnetic material. 28. Petroleum well according to claim 21, characterized in that the mentioned downhole injection device (60) further comprises a sensor (108), where the sensor (108) is electrically connected to the mentioned communication and control module and the said sensor is adapted to detect a trace material. 29. Petroleum well according to claim 21, characterized in that said communication and control module (80) comprises a modem (100).