DE60128446T2 - MARKING INJECTION IN A PRODUCTION ORL - Google Patents

Description

BACKGROUND OF THE INVENTION

Field of the invention

The The present invention relates to a petroleum well for conveying Petroleum products. In one aspect, the invention relates to systems and methods for monitoring a fluid flow while a petroleum production by controllably injecting tracer materials in at least a fluid flow with at least one electrically controllable underground tracer injection system a petroleum shaft.

Description of the state of technology

The controlled injection of materials into oil wells (i.e., oil wells and gas wells) is one established practice, often is used to increase extraction or to analyze eligibility conditions.

It is useful, dependent of the quantities of materials to be injected between injection types to distinguish. Size Volumes of injected materials are injected into formations, to displace formation fluids in the direction of production wells. The best known example is water flooding.

In In a less extreme case, materials become underground Shaft introduced, to effect a treatment within the shaft. Examples Such treatments include: (1) propellant for improving the Efficiency of a promotion by means of external energy supply; (2) paraffin solvent, to prevent deposition of solids on the riser; and (3) surface active Substances to the flow properties of sponsored To improve fluids. These types of treatment require a modification the shaft fluids themselves. Smaller quantities are needed, one However, these types of injection are typically supplied by an additional Pipe coming from the surface gone underground becomes.

Yet Further applications require that even smaller amounts of materials need to be injected such as. (1) corrosion inhibitor to corrosion of the shaft equipment to reduce or prevent; (2) scale inhibitor to To prevent or reduce scale formation on the shaft equipment; and (3) tracer materials for the flow characteristics of various Monitor shaft sections. In these cases are the needed ones Sufficiently small that the Materials can be supplied by an underground reservoir, where avoiding leading a utility pipeline underground from the surface. The successful application of procedures where a controlled Injection from an underground reservoir is necessary it, however, that means must be provided to operate the injection equipment underground and with it communicate. In existing practice, this requires use of electrical cables going deep from the surface to the injection modules run in the shaft. Such cables are expensive and not quite reliable, and as a result, they are in current promotion practice as undesirable considered.

The use of tracers to identify materials and track their flow is a well-established process in other industries, and the development of tracer materials and detectors has progressed to the point where materials in dilutions down to 10 ^-10 and millions of individually identifiable tagging substances are available. A representative leading supplier of such materials and detection equipment is Isotag LLC Houston, Texas.

The Use of tracers to flow patterns has been found in many fields of research, such as the Observation of biological circulatory systems in animals and plants, applied. They were also offered as a commercial service in the oil field, e.g. as a means of analyzing injection profiles. The usage from tracers to promotion in the oil field However, it is expected that existing procedures will require the onset of a require special equipment in the borehole, using of cables and hydraulic lines from the surface into the Depth of the shaft operated and controlled.

The injection system according to the preamble of claim 1 is known from the European patent EP 0 721 053 known. In the known system, a current impedance device is disposed around a portion of a duct structure of a duct and connected to a downhole gas lift valve.

BRIEF SUMMARY OF THE INVENTION

The The problems and needs outlined above are by the present Invention in large Scale solved and overcome. According to one Aspect of the present invention is a tracer injection system according to claim 1 for use provided in a shaft. The tracer injection system includes a current impedance device and an electrically controllable underground tracer injector. The current impedance device is generally for concentric positioning around a section of a pipeline structure of the shaft set up so that if a time-variant electric current through and along the section of the pipeline structure is transmitted, a voltage potential between one side of the current impedance device and another Side of the current impedance device forms. The electrically controllable Underground Tracer injector is designed to work with the pipeline structure over the voltage potential is electrically connected, which is formed by the current impedance device is that is set up so that they by the electric Power is rubbed, and is arranged so that in In response to an electrical signal a tracer material in the Shaft ejects into it.

According to one Another aspect of the present invention is a petroleum well according to claim 12 for conveying of petroleum products intended. The petroleum shaft comprises a pipeline structure, a source of a time-variant electrical Strom, an induction choke, an electrically controllable tracer injection device and an electrical return line. The piping structure includes a first section, a second section and an electrical conductive section that extends between the first and the second section and extends into these. The first and second sections are Distally distanced from each other along the piping structure. The source of a time-variant electrical current is with the electric conductive portion of the piping structure at the first portion electrically connected. The induction choke is around a section of the electrically conductive portion of the piping structure arranged on the second section. The electrically controllable tracer injection device comprises two device connections and is arranged on the second section. The electrical return line provides an electrical connection between the electrically conductive portion the piping structure at the second section and the power source ago. A first of the device connections is with the electrical conductive portion of the piping structure on a source side the induction choke electrically connected. A second of the device connections is with the electrically conductive portion of the piping structure on a return line side of the Induction reactor and / or the electrical return line electrically connected. According to one Another aspect of the present invention is a method according to claim 30 to promote of petroleum products from a petroleum shaft intended. The method comprises the steps: (i) providing a piping structure which extends within a bore of the duct; (ii) Provide an underground tracer injection system for the shaft, which is an induction throttle and an electrically controllable tracer injection device, wherein the induction choke underground around the piping structure is arranged so that, when a time-variant electric current is transmitted through the piping structure becomes, a voltage potential between one side of the induction choke and another side of the induction choke, wherein the electrically controllable tracer injection device arranged underground is, wherein the injector with the piping structure over the Voltage potential is electrically connected by the induction choke is formed, so that the Injection device to be operated by the electric current can and the injection device is arranged such that they are in Responsive to an electrical signal, ejecting a tracer material; and (iii) controllably injecting the tracer material into an underground flow within of the duct with the tracer injector during one Advancement. The method may further comprise the steps of: (iv) providing an underground sensor device within the shaft, which with the piping structure is electrically connected and the through the electric power can be operated; (v) Monitor the flow at a location downstream of the tracer injector; (Vi) Detecting the tracer material within the flow with the sensor device; and (vii) causing a change in flow when this is desirable is to achieve treatment or recovery goals.

BRIEF DESCRIPTION OF THE DRAWINGS

Further Objects and advantages of the invention will become apparent upon reading the following detailed description and by reference to the attached Drawings obviously. In the drawings is / are:

1 a schematic representation showing a petroleum production shaft according to a preferred embodiment of the present invention;

2A a schematic representation of an upper portion of a Erdölörderschachts according to another preferred embodiment of the present invention;

2 B a schematic representation of an upper portion of a Erdölörderschachts according to yet another preferred embodiment of the present invention;

3 an enlarged view of a downhole portion of the shaft of 1 ;

4 a simplified electrical diagram of the through the shaft of 1 formed electrical circuit;

the 5A - 5D schematic illustrations of various tracer injector and tracer material reservoir embodiments for an electrically controllable downhole tracer injector according to the present invention;

6 a schematic representation of a sensor device in a petroleum production shaft according to the present invention;

the 7A - 7E schematic representations of uniform inflow and injection profiles for different manhole configurations;

8th 5 is a graph showing fluid flow lines in a circular laminar flow tube in the case where fluids enter the tube uniformly along its wall along the length of the tube;

the 9A - 9J simplified schematic diagrams illustrating various exemplary configurations for placement of a tracer injector and a sensor device within a plurality of well configurations;

10 plots graphically normalized arrival times on the ordinate as a function of normalized depths on the abscissa for a simulation of inflow using 100 inflow zones;

11 graphically represents normalized arrival times on the ordinate as a function of normalized depths on the abscissa for simulation of inflow using 1000 inflow zones.

DETAILED DESCRIPTION THE INVENTION

Under now referring to the drawings, wherein the same herein Reference numerals used to be the same throughout to designate in the various representations are preferred embodiments of the present invention and further described. The figures are not necessarily to scale, and in some make the drawings have been for illustrative purposes only exaggerated certain places and / or simplified. The expert will realize that many possible Applications and variants of the present invention on the basis the following examples are possible embodiments of the present invention possible are.

As used in the present application, a "pipeline structure" may include a single pipe, a riser pipe, a casing, a sucker rod, a series of interconnected pipes, rods, passages, struts, lattices, supports, a branch or a lateral extension A preferred embodiment utilizes the invention in the context of a petroleum well, the piping structure comprising tubular, metallic, electrically conductive tubing or riser strands, but not the invention thereto For the present invention, at least a portion of the piping structure must be electrically conductive, such an electrically conductive portion combining the entire piping structure (eg, steel pipes, copper pipes) or a longitudinally extending electrically conductive portion may be longitudinally extending non-conductive portion. In other words, an electrically conductive piping structure is one that provides an electrically conductive path from a first portion where a power source is electrically connected to a second portion where a device and / or an electrical return line is electrically connected , The piping structure will typically be a conventional round metal riser, but the cross-sectional geometry of the piping structure or any portion thereof may vary in shape (eg, round, rectangular, square, oval) and size (eg, length, diameter, wall thickness) along any portion of the piping structure. Thus, a piping structure must have an electrically conductive portion extending from a first portion of the piping structure to a second portion the tubing structure, wherein the first portion is distally spaced from the second portion along the tubing structure.

The Terms "first Section "and" second Section ", like used herein, each generally defined to be a section, to designate a part or area of a pipeline structure, which may extend along the pipeline structure or not, located at any location chosen along the piping structure can be located and the closest one lying ends of the pipe structure may or may not.

Of the Term "modem" is used herein to any communication device for transmission and / or receiving electrical communication signals via a electrical conductors (e.g., metal). Consequently is the term "modem" as used herein is not on the acronym for a modulator (a device containing a voice or data signal into a form that transmits can be) / demodulator (a device that is an original Signal after modulating a high frequency carrier has limited). Also, the term "modem" is as used herein will, not on conventional Computer modems limited, convert the digital signals into analog signals and vice versa (e.g., digital data signals via the analog public Telephone dial network too send). If e.g. a sensor measurements in an analog format it may be that such measurements then only modulated (e.g., spread spectrum modulation) and transmitted Need to become and thus no analog / digital conversion is required. When Another example may be that a relay / slave modem or a communication device only identifying a received signal filter, amplify and / or must pass on.

Of the Term "valve" as used herein generally refers to any device that is effective to the flow to regulate a fluid. Examples of valves include, but are not limited on bellows gas lift valves and controllable gas lift valves, respectively can be used around the flow of lift gas in a riser pipe of a shaft to regulate. The inner and / or outer working methods of valves can vary widely, and in the present application, the valves described not limited to any particular configuration, as long as the valves are effective to regulate a flow. Some of the various types of flow regulating mechanisms include, but are not limited to on ball valve configurations, needle valve configurations, slider configurations and cage valve configurations. The methods of incorporation of the explained in the present application Valves can vary greatly.

Of the Term "electrical controllable valve ", as used herein refers generally to a "valve" (as just described), in response to an electrical control signal (e.g., a signal from a surface computer or from an electronic underground control module), closed, set, changed or can be throttled continuously. The mechanism that indeed moving the valve position may include, but is not limited to: an electric motor; an electric actuator; an electromagnet; an electrical switch; a hydraulic actuator by at least one electric actuator, an electric motor, a electrical switch, an electromagnet or combinations is controlled by it; a pneumatic actuator by at least an electric actuator, an electric motor, an electric Switch, an electromagnet or combinations thereof controlled becomes; or a spring-loaded device in combination with at least an electric actuator, an electric motor, an electric Switch, an electromagnet or combinations thereof. An "electric controllable valve "can a position feedback sensor for providing a feedback signal, that of the actual Position of the valve corresponds, include or not.

Of the The term "sensor" as used herein is, refers to any device that is the absolute Value or a change a physical quantity detected, determined, supervised, recorded or otherwise recorded. A sensor as described herein can be used to detect physical To measure sizes, which include, but not limited to are on: temperature, pressure (absolute as well as difference), flow velocity, seismic data, acoustic data, pH, salinity, valve positions, volume or almost any other physical data size. One Sensor as described herein may also be used the presence or concentration of a tracer material in a current to detect.

As used herein, the term "on the surface" refers to a position that is above about fifty feet deep within the earth. In other words, the term "at the surface" does not necessarily mean a position on the ground at ground level, but will used herein in a broader sense to refer to a location that is often easily or conveniently accessible at a wellhead where people can work. For example, "on the surface" may be on a table on a jobsite that is positioned on the floor at the manhole deck, it may be on a seabed or seabed, it may be on a high rigbed rig platform, or it may be in the 100 Also, the term "surface" may be used herein as an adjective to refer to a location of a component or region located "on the surface." For example, as would be herein For example, a "surface" computer may be a computer that is "on the surface."

Of the Term "underground" as used herein is, refers to a position or a position below from about fifty Foot deep within the earth. In other words, "underground" is used here in a broad sense used to refer to a job that is often not easy or conveniently accessible from a wellhead where people work can. For example, in an oil well, an "underground" site is often at or close to a petroleum production zone under the surface, independently of whether the production zone vertically, horizontally, laterally or at any other angle is reached in between. The term "underground" is also used herein as an adjective, which describes the location of a component or area. For example, would an "underground" device in one Shaft is a device that is "underground" as opposed to "surface".

As used in the present application, "wireless" means absence a conventional one insulated wire core, e.g. from an underground device to the surface extends. The use of the riser and / or the casing as an electrical conductor is considered "wireless".

In similar Way are according to the conventional Terminology of practice in the oil field The terms "upper," "lower," "near-surface," and "underground" are relative and relative at a distance along a depth of hole from the surface, the in diverted or horizontal shafts with a vertical View, which was measured with respect to a Vermessungsmeßwert match may or not.

1 is a schematic representation of a petroleum production shaft 20 according to a preferred embodiment of the present invention. The shaft 20 has a vertical section 22 and a side section 26 on. The shaft has a casing 30 that is within the borehole and through a formation 32 extends through, and a riser 40 extends within the casing to convey fluids from subsurface to surface during production operations. Thus, the in 1 shown petroleum production shaft 20 However, conventional practice in the well structure is similar to that of the present invention.

The vertical section 22 in this embodiment comprises a gas lift valve 42 and an upper packer 44 to promote by means of external energy supply for fluids within the pipeline 40 provide. Alternatively, however, other ways of providing delivery by means of external energy supply may be included to form further possible embodiments (eg, a pump linkage). Also, the vertical section 22 otherwise, to form many other possible embodiments. For example, in an improved form, the vertical section 22 comprise one or more electrically controllable gas lift valve (s), one or more additional induction throttles and / or one or more controllable packers with electrically controllable packer valves.

The side section 26 of the shaft 20 extends through a conveyor zone 48 (eg an oil zone) of the formation 32 therethrough. The casing 30 in the lateral section 26 is at the conveyor zone 48 perforated to allow fluids from the delivery zone 48 can flow into the casing. 1 shows only a side section 26 However, there are many lateral branches of the shaft 20 to be available. The well configuration typically depends, at least in part, on the arrangement of the production zones for a given formation.

Part of the riser 40 extends into the lateral section 26 in and ends with a closed end 52 behind the conveyor zone 48 , The position of the riser end 52 inside the casing 30 is by a side packer 54 which is a conventional packer, maintained. The riser 40 has a perforated section 56 at the conveyor zone 48 for a fluid inlet from the conveying zone 48 on. In further embodiments (not shown), the riser 40 over the conveyor zone 48 continue (eg to other conveyor zones), or the riser 40 can end with an open end for a fluid inlet.

An electrically controllable underground tracer injector 60 is inline on the riser 40 within the lateral section 26 connected and forms part of the riser assembly. The injector is upstream of the conveyor zone for easy placement 48 arranged next to the vertical section. In further embodiments, the injection device 60 however, be further disposed within a lateral section. An advantage of this, the injector 60 near the riser inlet 56 the conveyor zone 48 to arrange is that this is a desirable location for injecting a Tracermaterials. However, when the injector is removed relative to the riser inlet 56 is arranged as in 1 A tracer material can be shown in the riser inlet 56 at the conveyor zone 48 using a nozzle extension tube 70 be injected. The nozzle extension tube 70 thus provides a way to move a tracer material away from the injector at a location 60 to inject into a flow. Ejecting a tracer material at a location remote from (eg, upstream of) the injector 60 over the nozzle extension tube 70 allows a sensor configured to detect the tracer material on or within the injector 60 to arrange. (Such a sensor 108 is in 3 shown.) In other possible embodiments, the injection device 60 be set up so that they a tracer material at a location outside the riser 40 (eg directly into the conveyor zone 48 or in an annular space 64 inside the casing 30 ) can inject controllable. Therefore, an electrically controllable underground tracer injection device 60 placed underground at any point within a shaft where it is needed.

An electrical circuit is using various components of the duct 20 educated. Mains current for the electrical components of the injector 60 gets off the surface using the riser 40 and the casing 30 provided as electrical conductors. Thus, in a preferred embodiment, the riser serves 40 as a pipeline structure, and the casing 30 serves as an electrical return line to form an electrical circuit in the shaft 20 to build. Also, the riser 40 and the casing 30 as electrical conductors for communication signals between the surface (eg a surface computer system 64 ) and the electrical underground components within the electrically controllable underground tracer injector 60 used.

In 1 includes a surface computer system 64 a master modem 66 and a source of a time-variant stream 68 , However, as one skilled in the art will appreciate, the surface equipment may be different. A first computer connection 71 of the surface computer system 64 is on the surface with the riser 40 electrically connected and gives a time-variant electrical power in the riser 40 on when mains power is needed on and / or communicating with the underground devices. The power source 68 provides the electrical power that transports underground power and communication signals underground. The time-variant electrical current is preferably an alternating current (AC), but it can also be a varianter direct current (DC). The communication signal may be from the master modem 66 be generated and within the source 68 embedded stream. The communication signal is preferably a spread spectrum signal, but other forms of modulation or predistortion may alternatively be used.

A first induction choke 74 is around the riser in the vertical section 22 arranged below the place where the lateral section 26 from the vertical section. A second induction choke 90 is about the riser 40 around inside the side section 26 near the injector 60 arranged. The induction chokes 74 . 90 comprise a ferromagnetic material and are de-energized. Because the induction chokes 74 . 90 around the riser 40 are arranged around, each induction choke serves as a large inductor to the alternating current in the riser 40 and the casing 30 formed shaft circle. The induction chokes 74 . 90 are effective on the basis of their size (mass), geometry and their magnetic properties.

An insulated riser connection 76 is installed at the wellhead to the riser 40 from the casing 30 electrically isolate. The first computer connection 71 from the power source 68 passes through an insulated seal 77 on the hanger 88 through and is with the riser 40 under the insulated riser connection 76 connected. A second computer connection 72 of the surface computer system 64 is with the casing 30 electrically connected to the surface. Thus, the insulators prevent 79 the riser connection 76 a short circuit between the riser 40 and the casing 30 on the surface. Alternatively (or in addition) to the insulated riser connection 76 can a third induction choke 176 (please refer 2A ) around the riser 40 around over the location of the electrical connection for the first computer connection 71 be arranged with the riser, and / or the hanger 88 can be an isolated hanger 276 (please refer 2 B ), the insulators 277 has to the riser 40 from the casing 30 electrically isolate.

The side packer 54 at the riser end 52 within the lateral section 26 provides an electrical connection between the riser 40 and the casing 30 underground beyond the second induction choke 90 ready. A lower packer 78 in the vertical section 22 , which is also a conventional packer, provides an electrical connection between the riser 40 and the casing 30 underground under the first induction reactor 74 ready. The upper packer 44 of the vertical section 22 has an electrical insulator 79 on to a short circuit between the riser 40 and the casing 30 to prevent the upper packer. Also, as needed, various centralizers (not shown) having electrical insulators may be used to short circuits between the riser 40 and the casing 30 prevent over the entire shaft 20 be included. Such an electrical insulation of the upper packer 44 or a centralizer can be achieved in a variety of ways, as will be apparent to those skilled in the art. The upper and the lower packer 44 . 78 provide hydraulic isolation between the main vertical section borehole 22 and the lateral borehole of the lateral section 26 ,

3 is an enlarged view showing a portion of the lateral section 26 from 1 with the electrically controllable underground Tracer injector 60 shows in it. The injector 60 includes a communication and control module 80 , a tracer material reservoir and an electrically controllable tracer injector 84 and a sensor 108 , Preferably, the components of an electrically controllable underground tracer injector 60 all in a single, sealed riser sleeve 86 together as a module for ease of handling and installation, as well as to protect the components from the environment around them. In further embodiments of the present invention, the components of an electrically controllable underground tracer injector 60 but separated (ie without riser sleeve 86 ) or combined in other combinations. A first device connection 91 the injector 60 provides an electrical connection between the riser 40 on a source page 94 the second induction reactor 90 and the communication and control module 80 ago. A second device connection 92 the injector 60 provides an electrical connection between the riser 40 on an electrical return line side 96 the second induction reactor 90 and the communication and control module 80 ago. Although the lateral packer 54 an electrical connection between the riser 40 on an electrical return line side 96 the second induction choke 90 and the casing 30 can provide the electrical connection between the riser 40 and the casing 30 can also be accomplished in several ways, including but not limited to: another packer (conventional or controllable); a senior centralizer; a conductive fluid in the ring between the riser and the casing; or any combination thereof.

4 is a simplified electrical schematic similar to that in the bay 20 from 1 illustrated electric circuit illustrated. In operation and with reference to 1 and 4 Mains power and / or communication are in the riser 40 on the surface via the first computer connection 71 under the insulated riser connection 76 passed. The time-variant current is due to the insulators 79 the insulated riser connection 76 prevented from getting off the riser 40 over the hanger 88 to the casing 30 to flow. However, the time-variant current flows unhindered along the riser 40 until he hits the induction chokes 74 . 90 meets. The first induction choke 74 provides a large induction that prevents most of the current from being applied to the first induction choke 74 to flow through the riser. Similarly, the second induction choke 90 a large induction that prevents most of the flow from being introduced to the second induction choke through the riser 40 to flow. Due to the induction chokes 74 . 90 creates a voltage potential between the riser 40 and the casing 30 , The voltage potential is also formed between the riser 40 on the source side 94 the second induction choke 90 and the riser 40 on the electrical return line side 96 the second induction reactor 90 , Because the communication and control module 80 are electrically connected via the voltage potential formed, the majority of the in the riser 40 passed stream, which is not lost on the way, through the communication and control module 80 that conducts the mains power and / or communication for the injector 60 distributed or decoded. After flowing through the injector 60 the current returns via the side packer 54 and the casing 30 to the surface computer system 64 back. When the current is an alternating current, the flow direction of the current just described through the well 20 along the same path and vice versa.

Other alternative ways of making an electrical circuit using a duct structure of a duct and at least one induction reactor are described in the related applications, many of which can be used in conjunction with the present invention to supply utility power and / or communications to the electrically powered downhole equipment 60 to provide and to form further embodiments of the present invention.

Referring again to 3 includes the communication and control module 80 an individually addressable modem 100 , Energy treatment circles 102 , a control interface 104 and a sensor interface 106 , Because the modem 100 the underground injection device 60 individually addressable, more than one downhole device can be installed and operated independently of others.

In 3 is the electrically controllable injector 84 with the communication and control module 80 electrically connected and thus receives mains power and / or communication 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 injector 84 , The tracer material reservoir 82 is a closed reservoir, the tracer materials for injection into the flow by means of the tracer injector 84 stores and delivers. The tracer material reservoir 82 from 3 will not pass through the tracer material supply line. However, in other embodiments, this may be the case. However, this may be the case (not shown) extending from the surface. Therefore, the size of the tracer material reservoir 82 depending on the volume of tracer materials required for injection into the well 20 needed, vary. The tracer injector 84 a preferred embodiment comprises an electric motor 110 , a screw mechanism 112 and a nozzle 114 , The electric motor 110 is with the communication and control module 80 electrically connected and receives from this movement command signals. The nozzle extension tube 70 extends from the nozzle 114 in a heart 116 of the riser at the riser inlet 56 (further upstream) and provides a fluid passage from the tracer material reservoir 82 to the riser interior 116 ready. The screw mechanism 112 is with the electric motor 110 mechanically coupled. The screw mechanism 112 is used to in response to a rotary motion of the electric motor 110 Tracer materials via the nozzle 114 and over the nozzle extension tube 70 from the reservoir 82 out and into the riser interior 116 to move in. Preferably, the electric motor 110 a stepper motor, thus providing tracer material injection in incremental quantities.

In operation, the fluid flow flows from the conveyor zone 48 around the tracer injector 60 around when going through the riser 40 passes through to the surface. Commands from the surface computer system 64 are transmitted underground and by the modem 100 of the communication and control module 80 receive. In the injector 60 The commands are decoded and received by the modem 100 to the control interface 104 passed. The control interface 104 then commands the electric motor 110 operating and injecting the specified amount of tracer materials from the reservoir 82 in the fluid flow of the riser 40 into it. Thus, the tracer injector injects 60 in response to commands from the surface computer system 64 via the communication and control module 80 a tracer material controllable in the inside of the riser 40 flowing fluid flow as needed or desired.

The tracer injector 60 from 3 also includes sensors 108 , At least one of the sensors 108 is configured to detect the presence and / or concentration of a tracer material in the riser 40 flow through it detected. The sensors 108 are with the communication and control module 80 via the sensor interface 106 electrically connected. The tracer injector 60 may also include sensors for performing further measurements, such as a flow rate, a temperature or a pressure. The data from the sensors 108 be in the communication and control module 80 coded and can by the modem 100 to the surface computer system 64 be transmitted. During operation, when tracer material enters the riser inside 116 upstream through the tracer injector 84 (via the nozzle extension tube 70 ), the sensors detect 108 the tracer when it flows past in the stream. By measuring the time of arrival (the time from injection to detection) and / or the concentration of the detected tracer, the characteristics of the flow may be determined, as further described hereinbelow in more detail.

As will be appreciated by one of ordinary skill in the art, the mechanical and electrical arrangement and configuration of the components within the electrically controllable tracer injector 60 vary while still performing the same function - providing electrically controllable downhole tracer injection. For example, the contents of a communication and control module 80 quite simply a cable connection terminal for distributing electrical connections from the riser 40 or may be very complex, including (but not limited to) a modem, a rechargeable battery, a power transformer, a microprocessor, a memory device, a data acquisition card, and a motion control card.

The 5A - 5D illustrate some possible variants of the tracer material reservoir 82 and the tracer injector 84 which may be included in the present invention for further possible Aus forms of leadership. In the 5A - 5D is a nozzle extension tube 70 not included. Thus, in the 5A - 5D shown tracer injectors arranged to be located at the point where the tracer injection is desired. However, a nozzle extension tube can also in each of the in the 5A - 5D be shown embodiments.

In 5A includes the tracer injector 84 a compressed gas reservoir 118 , a pressure regulator 120 , an electrically controllable valve 122 and a nozzle 114 , The compressed gas reservoir 118 is in fluid communication with the reservoir 82 over the pressure regulator 120 and thus provides a generally constant gas pressure to the reservoir. The tracer material reservoir 82 has a bubble in it 124 containing the tracer materials. The pressure regulator 120 regulates the passage of pressurized gas from the compressed gas reservoir 118 is delivered to the reservoir 82 but outside the bubble 124 , The pressure regulator 120 However, it can be replaced by an electrically controllable valve. The pressurized gas exerts pressure on the bladder 124 and thus on the tracer materials in it. The electrically controllable valve 122 regulates and controls the passage of tracer materials through the nozzle 114 through and into the riser interior 116 into it. Because the tracer materials are inside the bladder 114 through the gas from the compressed gas reservoir 118 Pressurized, the tracer materials from the nozzle 114 forced out when the electrically controllable valve 122 is opened.

In 5B is the tracer material 82 in two volumes 126 . 128 through a bubble 124 acting as a partition between the two volumes 126 . 128 acts, divided. A first volume 126 inside the bubble 124 contains the tracer material, and a second volume 128 within the tracer material reservoir 82 , but outside the bladder, contains compressed gas. Thus, the reservoir 82 preloaded, and the pressurized gas exerts pressure on the tracer materials within the bladder 124 out. The tracer injector 84 includes an electrically controllable valve 122 and a nozzle 114 , The electrically controllable valve 122 is with the communication and control module 80 electrically connected and is controlled by this. The electrically controllable valve 122 regulates and controls the passage of tracer materials through the nozzle 114 through and into the riser interior 116 into it. The tracer materials are due to the gas pressure from the nozzle 114 forced out when the electrically controllable valve 122 is opened.

In the 5C embodiment shown is similar to that of 5B , the pressure on the bladder 124 However, by a spring element 130 provided. Also can in 5C the bladder is not needed when there is a movable seal (eg, a sealed piston) between the spring element 130 and the tracer materials within the reservoir 82 located. The skilled artisan will appreciate that there are many variants of the mechanical construction of the tracer injector 84 and the use of a spring element to provide pressure on the tracer materials.

In 5D includes the tracer material reservoir 82 a bubble 124 that is a tracer material 84 contains. The tracer injector 84 includes a pump 134 , a one-way valve 136 , a nozzle 114 and an electric motor 110 , The pump 134 is from the electric motor 110 powered by the communication and control module 80 is electrically connected and controlled by this. The one-way valve 136 prevents backflow into the pump 134 and the bubble 124 , The pump 134 drives the tracer materials out of the bubble 124 out, through the one-way valve 136 through, out of the nozzle 114 out and into the riser interior 116 into it. Thus, the use of the tracer injector 84 from 5D be beneficial in cases where the tracer material 82 is arbitrarily shaped to maximize the volume of tracer materials held therein for a given configuration since the reservoir configuration is not of the implemented configuration of the tracer injector 84 is dependent.

Thus, there are, as the examples in the 5A - 5D illustrate many possible variants for the tracer material reservoir 82 and the tracer injector 84 , Those skilled in the art will appreciate that there are many other variations for performing the functions of storing tracer materials underground in combination with controllably injecting the tracer materials into the riser interior 116 in response to an electrical signal can give. Variants (not shown) of the tracer injector 84 may further include a venturi nozzle; Pressure on the bladder provided by a turbo device that draws rotational energy from the fluid flow within the riser; Pressure is withdrawn from other areas of the formation which is routed via a pipeline; any combination of the parts 5A - 5D ; or any combination thereof (without being limited thereto).

The tracer injector 60 Tracer materials can not enter the riser interior 116 inject. In other words, a tracer injector may be configured to introduce tracer materials into the formation 32 , in the casing 30 or directly into the production zone 48 controllably injected. Also, a single tracer injector 60 be set up so that they several tracer materials (ie different tracer identifiers or signatures), such as by having multiple tracer material reservoirs 82 and / or multiple tracer injectors 84 having. A single tracer injector 60 may be arranged to inject tracer materials into a well at multiple locations, eg, by having a plurality of nozzle extension tubes 70 which extends to various places.

The tracer injector 60 may further include components to form further possible embodiments of the present invention, including but not limited to: other sensors, a modem, a microprocessor, a logic circuit, an electrically controllable riser valve, a plurality of tracer material reservoirs (which are different Tracers), multiple tracer injectors (which can be used to eject multiple tracer materials to multiple sites), or any combination thereof. The injected tracer material may be a solid, a liquid, a gas, or a mixture thereof. The injected tracer material may be a single component, multiple components or a complex formulation. Furthermore, there may be a plurality of controllable tracer injectors for one or more lateral sections, each of which is from the surface computer system 64 independently addressable, addressable in groups or uniformly addressable. Alternatively, by the surface computer system 64 can be controlled, the electrically controllable underground injection device 60 be controlled by electronics therein or by another underground device. In the same way, the electrically controllable underground injection device 60 control and / or communicate with other downhole devices. In an improved form of electrically controllable tracer injector 60 it includes at least one additional sensor each adapted to measure a physical condition such as, but not limited to: absolute pressure, differential pressure, fluid density, fluid viscosity, acoustic transmission or reflection properties, temperature or chemical composition. A tracer injector 60 can also no sensors (ie no sensor 108 ), and the sensor 108 for detecting a tracer material may be separated and removed (eg, downstream or at the surface) with respect to the tracer injector 60 be arranged.

6 illustrates an example of a separate downhole sensor device 140 that have their own corresponding induction choke 142 disposed proximate thereto for routing power and / or communication to the sensor device. The sensor device 140 includes a sensor 108 , a communication and control module 144 and a modem 146 , The through the sensor device 140 collected data may be sent to a surface computer system or other downhole device using the riser 40 and / or the casing 30 be transmitted as an electrical conductor.

In In yet another mode of operation, the tracers can be underground be generated by the use of electric currents, thereby the need for an underground chemical reservoir is bypassed. This method offers the possibility a continuous supply of a tracer, over the whole Schacht life. For example, changes in the pH of a natural Sols are affected by an electrolytic cell containing the salts in Chlorine gas and the metal hydroxide decomposed. Typically, sodium chloride decomposed into chlorine gas and the metal hydroxide. A PH sensor can be used to detect such a pulse of high pH water, that generated inline or collected and released as floodwater becomes. Another potentially useful electrically driven chemical reaction is the production of ozone, as they are e.g. used in devices to the biological Activity in Swimming pools and water supply systems. In a further application, a solid material in the shaft can be arranged and by a controlled release, which is achieved by a controlled pulse of electrical energy will be made to enter the shaft fluid flow. The solved Material is for the fluid environment of the well preferably unique, thereby detection is allowed at low concentrations. One example for such a solid material is a metallic zinc element. commercial Analytical devices provide the detection of many other compounds that can be generated electrically by the skilled person.

When checking the related applications, the skilled person will recognize that further Also other electrically controllable underground devices as well many induction chokes in a well may be included for further possible embodiments to form the present invention. Such further electrical controllable downhole devices include (but are not limited on): one or more controllable packers with electrically controllable Packer valves, one or more electrically controllable gas lift valve (s); one or more modems, one or more sensors; a microprocessor, a logic circuit; one or more electrically controllable riser valve (s) for controlling a flow from different lateral branches; and more electronic Components as needed.

In use, a number of applications of the present invention will appear both in conventional wells and in complex future designs. For example, in vertical wells that are completed over long intervals, the inflow profiles of production wells are of interest to correct for non-uniform inflow, thereby allowing for uniform degradation of the entire formation. Similarly, flooding operations in long completion intervals depend on achieving uniform injection profiles to clear the entire zone. The 7A and 7B illustrate schematically uniform infeed profiles for a vertical well.

In shafts with long horizontal completions, maintaining uniform profiles is less dependent on differences in geological layer permeabilities than on the pressure gradients along the shafts. These pressure gradients tend to promote high flow rates near the shaft heel (ie the horizontal section closest to the vertical part of the shaft). The 7C and 7D each illustrate schematically uniform inflow and injection profiles for a long horizontal completion.

Another application is the use of tracers to distinguish production in shafts with multiple lateral branches. In these shafts, it is important to know which branch is producing excess water or which branch is already exhausted. 7E schematically illustrates a uniform inflow profile for multiple branches. Thus, the illustrate 7A - 7E the desirable airfoils for only a few of the many possible manhole configurations that are heavily dependent on the natural structure of the production zones in a given formation.

The movement of fluids in a subterranean well can be monitored by injecting tracers at various locations and observing the time of arrival and dissolution of fluids entering the well downstream of the tracer injection point. As described above, the tracers are from a storage reservoir 82 inside an injector 60 injected into a flow. Alternatively, however, a tracer may be powered by electrical methods within the injector 60 be generated.

The Movement of an intermittent River in a manhole flow injected tracers is dependent from the degree of mixing during his transport along the shaft. In the case of a simple one flow in a tube changes the velocity profile with the radial position, so that fluids move slightly faster in the middle of the pipe than on the wall. When a flow in the laminar region (i.e., at low rates) the form of the velocity profile parabolic, and in the case of none Sliding movement on the wall would a tracer over the length the flow be scattered. In practice, usually occurs because the pipe walls rough are and a flow fast is a turbulent flow on. The turbulence mixes the fluids so that the tracers are more uniformly transported and in general the average flow velocity in the Play the pipe.

In conveying or injection wells, which are completed with perforated or mesh linings done an inflow of fluids through the tube wall into the flow along the shaft. In this case, there is a flow of a fluid entering the shaft on the wall at various positions along the open interval, more complex. below Examples given refer to flow in either vertical or horizontal shafts, However, a vertical well is used to cover the case of a laminar flow to demonstrate by an inflow along an open Interval takes place.

Under Condition that the flow laminar and no mixing takes place across the flow lines of the flow, fill that Fluid entering the bottom of the open interval Start the entire cross section of the hole. Surface nearer throttles an additional one Inflow of Fluids the initial Fluid that has entered the bottom and drives it radially inside. At the top of the open interval is the last occurred fluid in the radial area near the wall and the initial one Fluid that has entered at the bottom is located in the Middle of the shaft. Thus, tracer sensors should be arranged such be that she the tracers in the passing flow intercept. The use of a turbulator (not shown) immediately upstream from the sensor to the tracer flow to the mainstream to mix, can for be beneficial to this purpose.

Referring again to 7A , which illustrates the flow pattern for a fluid flowing at a uniform rate into a circular tube, this flow pattern can be established with the following model:

assumptions:

• 1) uniform inflow of fluids in the shaft; and
• 2) uniform Speed profile inside the shaft.

These Assumption is in some contradiction to the expectation of parabolic Speed profiles for a flow in a tube without sliding on the wall. In this case, however, As fluids enter the wall, the flow approaches more a plug-flow.

definitions:

• q

  = Inflow / interval length unit

  L

  = Height above the Bottom of the open interval

  L _i

  = Fluid (tracer) inflow point above the Bottom of the open interval

  L ₀

  = Total height of open interval

  f

  = Proportion of shaft area, by a current is taken from the interval from 0 to L.

  v

  = Flow velocity at the height L

  r ₀

  = Radius of the shaft

  r

  = Flow radius of fluids in the shaft that entered the shaft below L are

Now assume that fluids enter the well at a certain height Li above the bottom of the bottom of the well into the well. At heights above this (L is equal to or greater than Li), the fraction of the well cross-sectional area occupied by the fluids that have entered below Li is: f = qL i / qL = vπr 2 / vπr 0 2 (1)

Thats why: L = L i (r 0 / R) 2 (2)

The graphic representation in 8th Figure 11 shows flowlines of a flow in a well when fluids enter the well uniformly at a depth. When a flow is turbulent, as is the case in most wells, the flow lines are mixed. Under these conditions, the graphical representation of 8th the proportion of a flow at a given depth (instead of the radial position) formed of fluids that have entered the well below that depth.

In order to derive information about fluid movement in wells, it is necessary to understand the time of arrival and the concentration of tracers that can be injected at different positions in the flowing flow. The use of the present invention provides ways to controllably inject a tracer material at virtually any location underground and / or to detect the presence of the tracer material or its concentration within the flow at virtually any location underground. The 9A - 9J are just a few examples of the many possible arrangements of tracer injectors 60 (the one sensor 108 or not) and / or sensor devices 140 ready in a delivery or injection shaft. Again, the desirable configuration of a well is typically dependent on the design of production zones 48 in a formation 32 , The underground tracer injectors 60 and underground sensor devices 140 can be permanently installed or not. Durable downhole devices are preferred because of the cost and time required to add, remove, modify, replenish or exchange a downhole device. The present invention makes it possible to permanently install downhole devices, as the present invention provides, among other things, innovative ways to provide power and / or communication to such permanent underground devices.

9A Figure 5 is a simplified schematic illustrating a possible configuration of the present invention in a vertical production well. In 9A are five underground tracer injectors (T ₁ -T ₅ ) 60 at various locations along the depth of the vertical shaft at the conveyor zone 48 for injecting tracer materials into the flow at different depths. An underground sensor device 140 is upstream of the tracer injectors (T ₁ -T ₅ ) 60 arranged to detect tracer materials in the flow as they pass. The sensor device 140 can have multiple sensors 108 which are adapted to detect a different tracer material signature, the different tracer injection devices (T ₁ -T ₅ ) 60 correspond. Alternatively, the same tracer may be used in all injector devices and the origin of the tracer pulse determined by individually selecting the injector device. Thus, a tracer material delivered by the middle tracer injector (T ₃ ) provides 60 ejected and at the sensor device 140 is detected, information about the flow in the riser 40 at the middle tracer injection device (T ₃ ) 60 entry. The underground sensor device 140 can also be arranged on the surface. However, it is more desirable that in some cases the downhole sensor device 140 is positioned closer to the tracer injection point so that the tracer material is less diluted by fluids in the flow.

9B Figure 5 is a simplified schematic illustrating another possible configuration of the present invention in a vertical production well. In 9B are five underground tracer injectors (T ₁ -T ₅ ) 60 at various locations along the depth of the vertical shaft at the conveyor zone 48 for injecting tracer materials into the flow at different depths. Instead of a sensor device 140 , as in 9A are shown in 9B however, five separate downhole sensor devices (S ₁ -S ₅ ) 140 in different places along the depth of the vertical shaft. Each sensor device (S ₁ -S ₅ ) corresponds in each case to a tracer injection device (T ₁ -T ₅ ) 60 , Thus, the sensor device S ₄ comprises a sensor 108 adapted to receive one of the tracer injectors (T ₄ ) 60 ejected tracer material detected. In such a configuration, a sensor device 140 in the same place as a tracer-A injection device 60 (eg sensor device S ₂ and tracer injection device T ₃ ) to be electrically connected to the other, can be electrically connected via a same induction choke, can work from a same communication and control module, can share a same modem and / or can within a same housing includes.

9C Figure 5 is a simplified schematic diagram illustrating one possible configuration of the present invention in a vertical injection well. In 9C are six sensor devices (S ₁ -S ₆ ) 140 configured to provide a tracer material that is surface-active by a tracer injector 60 is injected, detect. For injection wells, it is typically only necessary to inject the tracer materials on the surface since most or all of the flow is from the surface. However, it is also possible to have one or more tracer injectors 60 underground in addition to or in place of the tracer injector 60 to arrange on the surface.

The configurations of 9A - 9C can be combined so that the arrangement of tracer injectors 60 and sensor devices 140 provides tracer detection and controllable tracer injection for use during both production and injection stages in delivering petroleum to a manhole. Consequently, the shaft can be switched from a delivery stage to an injection stage (and vice versa) without the need for tracer injectors 160 and sensor devices 140 to reconfigure underground in the manhole. Therefore, the tracer injectors 60 and the sensor device 140 permanently installed for long-term use and for various applications.

9D Figure 5 is a simplified schematic illustrating one possible configuration of the present invention in a hoistway with a horizontal completion. In 9D are seven underground tracer injectors (T ₁ -T ₇ ) 60 at various locations along the horizontal section at the conveyor zone 48 for injecting tracer materials into the flow at various locations. As in 9A is a downhole sensor device 140 upstream from the tracer injectors (T1-T7) 60 arranged to detect tracer materials in the flow as they pass.

9E Figure 5 is a simplified schematic illustrating another possible configuration of the present invention in a hoistway with a horizontal completion. The configuration in 9E is the same as the configuration in 9B , except that a sensor or sensors 108 is arranged to detect tracer materials on the surface / are. The sensor 108 can be an autonomous sensor device 140 or he can be part of a surface computer system 64 be.

9F Figure 4 is a simplified schematic illustrating another still possible configuration of the present invention in a hoistway with a horizontal completion. The configuration in 9F is similar to the configuration in 9B , as multiple sensor devices (S ₁ -S ₇ ) 140 present to the multiple tracer injectors (T ₁ -T ₇ ). 60 correspond.

9G FIG. 10 is a simplified schematic diagram illustrating one possible configuration of the present invention in an injection well having a horizontal portion. FIG. The configuration in 9G is similar to the configuration in 9C than several underground sensor devices (S ₁ -S ₇ ) 140 are set up so that they are a Tracermaterial by a tracer injection device 60 at the surface is injected into the shaft, detect. Alternatively, the tracer injector 60 be arranged underground.

9H Figure 3 is a simplified schematic illustrating one possible configuration of the present invention in a production well having multiple side completions. In 9H are tracer injection devices (T ₁ -T ₄ ) 60 within the lateral branches, with each tracer injector 60 is located near the fork between a side branch and the main wellbore. Such an arrangement of tracer injectors (T ₁ -T ₄ ) 60 has the advantage of easy installation (with respect to installing a device further underground into a lateral branch). A sensor device 140 is located upstream of the uppermost lateral branch. The sensor device 140 is set up to receive tracer materials passing through the tracer injectors (T ₁ -T ₄ ) 60 are injected into the lateral branches, detected. Thus, the sensor device 140 several sensors 108 which are adapted to detect multiple tracer material signatures. Alternatively, the sensor device may 140 or sensors 108 be arranged on the surface, in 9H However, the underground arrangement shown is sometimes preferred.

9I Figure 5 is a simplified schematic illustrating another possible configuration of the present invention in a production well with multiple side completions. In 9I are located as in 9H , Tracer injectors (T ₁ -T ₄ ) 60 , a short distance within the lateral branches. In 9I however, there are four sensor devices (S ₁ -S ₄ ) 140 , one corresponding to each tracer injection device (T ₁ -T ₄ ) 60 , available. Thus, the sensor device S _{3 is} arranged to detect a tracer material injected into the flow by the tracer injector T ₃ , which provides flow information regarding the lateral branch having the tracer injector T ₃ therein. Since the sensor devices S ₃ and S _{4 are located} at the same location, they can become a single sensor device 140 combined, the multiple sensors 108 having.

9J FIG. 4 is a simplified schematic diagram illustrating yet another possible configuration of the present invention in a production well having multiple side completions. FIG. In 9J are tracer injectors (T ₂ -T ₄ ) 60 within the lateral branches near the conveyor zones 48 arranged, and a tracer injection device (T ₁ ) 60 is located within the vertical section under the lateral branches. Sensor devices (S ₂ -S ₄ ) 140 are each upstream of the tracer injectors (T ₂ -T ₄ ) 60 located within the branches near the vertical section. A sensor device (S ₁ ) is arranged upstream of the tracer device (T ₁ ) and under the lateral branches. Consequently, the flow in each section of the shaft can be monitored independently.

For those in the 9A - 9J illustrated configurations in which multiple tracer injectors 60 and / or multiple sensor devices 140 Tracer injectors can be present 60 and / or the sensor devices 140 be arranged at equally spaced intervals. The multiple tracer injectors 60 and / or the sensor devices 140 however, they may be spaced apart randomly or in any spacing arrangement. Furthermore, each of the multiple tracer injectors 60 and / or the sensor devices 140 have their own induction choke to provide power and / or communication, or some or all of the tracer injectors 60 and / or the sensor devices 140 share an induction choke. Because the tracer injectors 60 and the sensor devices 140 independently addressable and independently controlled, one or more well sections can be independently monitored.

Several calculations are presented below to illustrate how information or measurements obtained while the present invention is used can be used to determine fluid movement or flow characteristics of a well during production or injection. The calculations provided below serve as a model for an influx of fluids into a production well. However, with a slight modification, they may also be applied to injection well profiles in which a tracer is injected at a location at the top of the interval and an arrival time at spaced monitors along the open in tervalls is observed.

definitions:

• Δx _i

  = Thickness of the layer i

  H

  = Total interval thickness

  ii

  = Inflow in the shaft per unit length the layer i

  qi

  = ii Δxi = flow rate in the shaft of the layer i

  q _T

  = Σ q _i = total flow rate into the shaft

  Q _i

  = Flow rate in the shaft at a depth of the layer i

  Q _T

  = Total flow rate from the shaft = q _T

  n

  = Number of intervals (counted from top to bottom)

  N

  = Total number of intervals

  v _β

  = Volume of the injected tracer pulse

  c _β

  = Concentration of the Tracers in injected pulse

  v _β c _β

  = Mass of the injected Tracers

  r

  = Radius of the shaft

  t _i

  = Transit time over the Layer i

assumptions:

• Ax 1  = Δx 2  = Δx 3  = ... Δx n  (1)
• i 1 Ax 1 + i 2 Ax 2 + i 3 Ax 3 ... + i n Ax n = q T (2) (no cross flow)

CASE I: Uniform inflow

• i i = constant (3)

The flow rate in the well at layer i is the sum of the inflows in all layers below and in layer i: Q i = q N + q N-1 + ... + q i (4)

The transit time over the layer i is: t i = (πr 2 Ax i ) / (Q i ) = (πr 2 Ax i ) / (Σ i N i i Ax i ) = (πr 2 ) / (Σ i N i i ) (5)

The total transit time from inflow from layer k to the top of the interval is: t tk = t 1 + t 2 + t 3 (6) t tk = Σ I k t I (7)

An example of a calculation for four layers with a constant inflow rate is given below. Beginning at the bottom of the interval, the flow rate within the well increases as each layer flows into the well in turn (see Table 1, Column 2). For this case, where the layer thicknesses are the same, the well volume is the same with respect to each layer. Therefore, the passage time of fluids in the well above this layer is inversely proportional to the flow rate in the well (see Table 1, column 3). Summing up these layer transit times from top to bottom to a layer in which a tracer has been injected into the flow, this results in the total transit time for a tracer until it arrives at the top of the delivery interval (see Table 1, column 4). , An injected tracer is diluted by inflowing fluids entering above the tracer injection point. Thus, the concentration of the tracer arriving at the top of the interval can be calculated relative to the initial injected concentration by dividing the flow rate in the well at the injection point by the flow rate at the top of the interval, ie by the total flow rate ( see Table 1, column 5). TABLE 1 layer Flow in the shaft Layer transit time t _i = πr ² / Σi _i Total transit time t _TK = t ₁ + t ₂ + t ₃ + t ₄ arrival concentration 1 q ₁ + q ₂ + q ₃ + q ₄ πr ² / 4i _i (πr ² / i _i ) (1/4) 4.4 2 q ₁ + q ₂ + q ₃ πr ² / 3i _i (πr ² / i _i ) (1/4 + 1/3) 3.4 3 q ₁ + q ₂ πr ² / 2i _i (πr ² / i _i ) (1/4 + 1/3 + 1/2) 2.4 4 q ₁ πr ² / 1i _i (πr ² / i _i ) (1/4 + 1/3 + 1/2 + 1 /) 1.4

10 Figure 12 illustrates the relative arrival times at the top of the interval for fluids entering the well at 100 points along the interval.

11 Figure 12 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 thicknesses

For this more complex case, the flow rate of a fluid entering a vertical well from a bed is a function of the permeability ratio (k), the thickness (Δy _i ), and the normalized inflow determined by the pressure gradient. q i = k i i i Dy i = Flow rate from layer i into the shaft (8) in which
i _i = constant

Again, the flow rate in the well at layer i is the sum of the inflows in all layers below and in layer i: Q i = q N + q N-1 + ... + q i (9)

Wherein the flow rate from the bottom to the layer i is summed and the transit time is over the layer: .delta.t i = (πr 2 Dy i ) / (Q i ) = (πr 2 Dy i ) / ΣN i (Δij kj ΔYJ) (10)

The total transit time of fluids in the well from inflow at the i-layer to the upper-most of the interval is: (The transit times are summed from layer 1 at the top of the interval down to layer i.) .delta.t Ti = Δt 1 + Δt 2 + ... + Δt i (11) .delta.t Ti = Σ 1 i .delta.t k (12)

Manholes with several lateral horizontal completions

When manholes are completed with several lateral horizontal branches, as in the 9H - 9J As shown, the productivity of individual branches can not be determined by conventional registration and profile measurements. Information about the productivity of individual branches would be useful for reservoir management, which could lead to overwork or backfilling of shafts in the direction of poorly completed branches. Similarly, it is useful if the production from a well, as observed on the surface, indicates a sudden increase in water or gas to determine which turn causes the problem. In the simplest application of the use of tracers for a diagnosis of a lateral well, the tracer injection point may have a short distance into the branch with the help of one of the arrangement methods explained above (see 9H and 9I ) to be ordered. The detector may be located in the vertical portion of the well above the topmost branch. Branches that have low productivity show a long response to a dilute tracer because the transit time in this branch is long compared to that in the vertical tube.

Injection wells with long vertical open intervals

In formations that are flooded with water over long intervals, the maintenance of uniform injection profiles is essential to ensure effective flooding of the entire oil-bearing zone. In a typical injection well completion, fluid is injected through a riser below a packer and may enter the target zone through perforations in the casing or through a sieve insert. In this application, a number of detectors may be installed along the casing or insert, or preferably along a perforated extension of the riser below the packer (see 9C ). In this configuration, the tracer can be injected on the surface and the arrival times at the various detectors used to determine the injection profile. With a surface reading of the detectors, a complete history of the fluid injection profile over the entire flooded zone can be obtained. In the case of injection wells, particular care must be taken to thoroughly mix the injected tracer to avoid separate flow near the wall of the tube. The reason for this is that fluids leak out of the shaft on the wall; thus, a tracer remaining near the wall exits the well in the upper layers and is not available for measurements at the lower zones.

in the Unlike injection wells, where the tracer moves radially outward when the flow is the Hole moves down, have chutes one radial movement inwards when the conveyed Move fluids up. Unless mixed, take a tracer injected at the shaft is ultimately just that Center of the shaft, when he flows up the shaft. The means no There is a risk that the Tracer exits the shaft, but at the detection point must Care should be taken to avoid that the passing of the Tracers failed when the detector is placed against the wall. One possible solution is the use of turbulators in the shaft, the immediate are arranged under the detectors to ensure that a tracer flowed past the wall.

The The above analyzes assume a dominant phase, the flows in the shaft and can be observed with the aid of a single tracer. In In practice, most manholes have combinations from oil, Water and gas flowing in the shaft. In these conditions can they Drives in a fast transport of phases compared with the average fluid velocity result. In conventional oil and gas wells lies a wide variety of underground conditions, and there are many possibilities, Underground detectors for special funding conditions to use. These conditions should be understood by those skilled in the art known from conveyor shafts be.

One Example of useful Information obtained with the help of such devices could is the arrangement of entry points for water or gas. At the flood of water There is often a difference between the salinity of the water original Formation and that of the injected flooding water. The arrival of fresh water at the surface at individual shafts of a Water flooding was used for many years to make a breakthrough to monitor. However, it is in shafts with long intervals not easy, the specific zone in the to know vertical section that breaks through. Permanently fastened Detectors arranged along the open interval, can used to monitor the progress of a flooding and a line for Remedial work to exclude the water breakthrough provide.

Delivery shafts with long horizontal open intervals

Unlike vertical shafts with long completions, wells with long horizontal completions are usually completed in a single geological layer, and thus their productivity profiles are less dependent on differences in layer permeability. In these shafts, maintaining uniform profiles is equally important. However, the pressure gradient along the open interval often results in higher heel feed rates than at the toe of the well because a larger pressure drop can be achieved near the vertical portion (the heel). High flow rates in sections of the open interval can cause early gas from above the oil well or water enters from below. Tracer monitoring with spaced devices in the horizontal section (see 9D - 9G ) would be useful for providing information for proper control of the inflow in these wells.

Of the Amount of high productivity at the heel, by calculating the effect of a distributed inflow of Fluid from the formation can be checked at the pressure drop along the shaft.

From the reservoir pressure dependent inflow

The inflow quantity in the manhole is proportional to the difference between the reservoir pressure and the pressure in the shaft. As the pressures in the shaft along of the open interval are dependent on the flow, the inflow profile be procured by an iterative calculation.

Therefore can by using the present invention and those provided therein Calculations the currents in a funding or injection well monitored and characterized in real time as needed become. Provided by the use of the present invention Information can more knowledge about deliver the underground events and can be used be used to guide operators or a computer system, the funding or to change injection method, to optimize operations. Such uses may be for an existing formation increase the efficiencies and oil production maximize. The present invention can also be applied in other ways of shafts (other as petroleum shafts), like e.g. a water delivery shaft, be applied.

Claims (33)

Injection system for use in a shaft ( 20 ), comprising: a current impedance device ( 74 . 90 . 142 ), which are suitable for positioning around a section of a pipeline structure ( 40 . 96 ) of the shaft and for inhibiting one along the portion of the pipeline structure ( 40 . 96 ) passed time-variant electrical signal is set up; characterized in that the system further comprises: an electrically controllable underground tracer injection device ( 60 ) arranged to be in communication with the pipeline structure ( 40 . 96 is electrically connected, is operated so that it is operated by the time-variant electrical signal, and is set up so that a tracer material in the shaft ( 20 ) into it. An injection system according to claim 1, wherein the current impedance device ( 74 . 90 . 142 ) has a substantially annular geometry and comprises a ferromagnetic material. An injection system according to claim 1, wherein the pipeline structure ( 40 . 96 ) at least a portion of a riser ( 40 . 96 ) of the shaft and the electrical return line at least a portion of a casing ( 30 ) of the shaft ( 20 ). An injection system according to claim 1, wherein the pipeline structure comprises at least a portion of a casing ( 30 ). An injection system according to claim 1, wherein the injection device ( 60 ) an electric motor and a communication and control module ( 80 ), wherein the electric motor ( 110 ) with the communication and control module ( 80 ) is electrically connected and arranged such that it is controlled by the latter. An injection system according to claim 1, wherein the injection device comprises an electrically controllable valve ( 122 ) and a communication and control module ( 80 ), wherein the electrically controllable valve ( 122 ) with the communication and control module ( 80 ) is electrically connected and arranged such that it is controlled by the latter. An injection system according to claim 1, wherein the injection device ( 60 ) a tracer material reservoir ( 82 ) and a tracer injector ( 84 ), wherein the tracer material reservoir ( 84 ) in fluid communication with the tracer injector ( 84 ), and the tracer injector ( 84 ) is arranged to cause the tracer material from within the tracer material reservoir from the injection device (in response to an electrical signal). 60 ) ejects. An injection system according to claim 1, wherein the electrical Signal is a power signal. An injection system according to claim 1, wherein the electrical signal is a communication signal for controlling the operation of the tracer injector (10). 60 ). An injection system according to claim 1, further comprising a sensor ( 108 ) arranged to detect the tracer material when the tracer material on the sensor ( 108 ) flowed past in a current. An injection system according to claim 1, further comprising a nozzle extension tube (16). 70 ) extending from the tracer injector ( 60 ). Petroleum well for petroleum product equipped with an injection system according to claim 1, comprising: a pipeline structure ( 40 . 96 ) located within the wellbore ( 20 ) is arranged. Petroleum well according to claim 12, wherein the current impedance device ( 74 . 90 . 142 ) includes an electroless induction choke with a ferromagnetic material such that the induction choke is sized based on its size, geometry, spatial relationship relative to the piping structure ( 40 . 96 ) and their magnetic properties. Petroleum well according to claim 12, wherein the pipeline structure ( 40 . 96 ) a riser ( 40 . 96 ) and a casing ( 30 ), wherein the time-variant signal on at least one of the riser ( 40 . 96 ) and the casing ( 30 ) is created. Petroleum well according to claim 12, wherein the tracer injection device ( 60 ) an electrically controllable valve ( 122 ). Petroleum well according to claim 12, wherein the tracer injection device ( 60 ) an electric motor ( 110 ). Petroleum well according to claim 12, wherein the tracer injection device is a modem ( 100 ). Petroleum well according to claim 12, wherein the tracer injection device comprises a tracer material reservoir ( 82 ). Petroleum well according to claim 12, further comprising a sensor ( 108 ) arranged to detect a tracer material. A petroleum well according to claim 12, further comprising a nozzle extension tube (14). 70 ) extending from the tracer injector ( 60 ). Petroleum well for production of petroleum products according to claim 12, comprising: a casing ( 30 ) located within a wellbore ( 20 ) extends; a pipeline structure ( 40 . 96 ) located inside the casing ( 30 ), wherein the pipeline structure ( 40 . 96 ) is a riser; a source of a time-variant electrical current ( 68 ), which is arranged on the surface, wherein the power source with at least one of the riser ( 40 . 96 ) and the casing ( 30 ) and is arranged to output a time-variant current to at least one of the two; the underground tracer injection device ( 60 ) a communication and control module ( 80 ), a tracer material reservoir ( 82 ) and an electrically controllable tracer injector ( 84 ), wherein the communication and control module ( 80 ) with at least one of the riser ( 40 . 96 ) and the casing ( 30 ), and wherein the tracer injector ( 60 ) with the communication and control module ( 80 ) and the tracer material reservoir ( 82 ) in fluid communication with the tracer injector ( 60 ) stands; an underground current impedance device ( 70 . 90 . 142 ) around a portion of at least one of the riser ( 40 . 96 ) and the casing ( 30 ), and wherein the current impedance device is arranged to receive a portion of the electrical current through the communication and control module (12). 80 ) passes through. Petroleum well according to claim 21, comprising a sensor device which is connected to at least one of the riser (11). 40 . 96 ) and the casing ( 30 ), wherein the sensor device comprises a sensor ( 108 ) arranged to receive a tracer material in a flow of the well ( 120 ) detected. An oil well according to claim 21, further comprising a nozzle extension tube (14). 70 ) extending from the tracer injector ( 60 ). Petroleum well according to claim 21, wherein the tracer injector ( 60 ) an electric motor ( 110 ), a screw mechanism ( 112 ) and a nozzle ( 114 ), wherein the electric motor ( 110 ) with the communication and control module ( 80 ) is electrically connected, the screw mechanism ( 112 ) with the electric motor ( 110 ) is mechanically coupled, the nozzle ( 114 ) into an interior of the riser ( 40 . 96 ), the nozzle ( 114 ) a fluid passage between the tracer material reservoir ( 82 ) and the riser interior, and the screw mechanism ( 112 ) is arranged such that it is in response to a rotational movement of the electric motor ( 114 ) Tracer material over the nozzle ( 110 ) from the tracer material reservoir ( 82 ) out and into the riser inside leads. Petroleum well according to claim 21, wherein the tracer material reservoir ( 82 ) a separating device ( 124 ) containing an interior of the tracer material reservoir ( 82 ) is divided into two volumes, and wherein the tracer injector is an electrically controllable valve ( 122 ) and a nozzle ( 114 ), a first of the reservoir interior volume containing a tracer material, a second of the reservoir interior volume ( 118 ) contains a pressurized gas so that the gas exerts a pressure on the tracer material in the first volume ( 124 ), wherein the electrically controllable valve ( 122 ) with the communication and control module ( 80 ) is electrically connected and controlled, and the first volume ( 124 ) via the electrically controllable valve ( 122 ) and over the nozzle ( 114 ) is in fluid communication with an interior of the riser. Petroleum well according to claim 21, wherein the tracer material reservoir ( 82 ) a separating device ( 124 ), which divides an interior of the tracer material reservoir into two volumes, and wherein the tracer injector comprises an electrically controllable valve ( 122 ) and a nozzle ( 114 ), a first of the reservoir internal volumes ( 124 ) contains a tracer material, a second of the reservoir in nenvolumen a spring element ( 130 ), so that the spring element ( 130 ) exerts a pressure on the tracer material in the first volume, wherein the electrically controllable valve ( 122 ) with the communication and control module ( 80 ) is electrically connected and controlled, and the first volume ( 124 ) via the electrically controllable valve ( 122 ) and over the nozzle ( 144 ) is in fluid communication with an interior of the riser. Petroleum well according to claim 21, wherein the current impedance device ( 74 . 90 . 142 ) comprises an electroless induction choke with a ferromagnetic material. Petroleum well according to claim 21, wherein the underground injection device ( 60 ) a sensor ( 108 ), wherein the sensor ( 108 ) is electrically connected to the communication and control module and the sensor is adapted to detect a tracer material. Petroleum well according to claim 21, wherein the communication and control module ( 80 ) a modem ( 100 ). Method for operating a crude oil shaft, comprising the steps of: providing a pipeline structure ( 40 . 96 ) located within a hole of the shaft ( 20 ) extends; Applying a time-variant electrical current to the pipeline structure ( 40 . 96 characterized in that the method further comprises the steps of: operating a downhole tracer injection system ( 60 ) for the shaft ( 20 ) using a pipe structure ( 40 . 96 ) applied time-variant electric current; and injecting a tracer material from the tracer injection system into an underground flow within the well ( 20 ). The method of claim 30, further comprising the steps of: monitoring the flow at a location remote from the tracer injector (10); 60 ) is located; and detecting the tracer material within the flow. The method of claim 30, further comprising the step of: transmitting data corresponding to the detection steps to a surface computer system ( 64 ) via the pipeline structure ( 40 . 96 ). The method of claim 30, further comprising the steps of: Arranging a reservoir of a tracer material ( 82 ) in the main wellbore ( 22 ) of the shaft ( 20 ); Injecting the tracer material into a lateral branch ( 26 ) extending from the main wellbore ( 22 ), via a capillary tube extending into the lateral branch ( 26 ).