OA13129A

OA13129A - Tracer injection in a production well.

Info

Publication number: OA13129A
Application number: OA1200200273A
Authority: OA
Inventors: George Leo Stegemeier; Harold J Vinegar; Robert Rex Burnet; William Mountjoy Savage; Frederick Gordon Carl Jr; John Michele Hirsch
Original assignee: Shell Int Research
Priority date: 2000-03-02
Filing date: 2001-03-02
Publication date: 2006-12-13
Also published as: RU2002126211A; BR0108888A; WO2001065053A1; AU2001243391B2; EP1259700B1; DE60128446D1; EP1259700A1; CA2402163C; NO326367B1; AU4339101A; MXPA02008508A; NO20024137D0; NO20024137L; BR0108888B1; CA2402163A1; DE60128446T2; RU2263783C2

Abstract

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

Description

BACKGROÜND OF THE INVENTION

Field of the Invention

The présent invention relates to a petroleum well for producing petroleum products. Inone aspect, the présent invention relates to Systems and methods for monitoring fluid flowduring petroleum production by controllably injecting tracer materials into at least one fluidflow stream with at least one electrically controllable downhole tracer injection System of apetroleum well.

Description of Reiated Art

The controlled injection of materials into petroleum wells (i.e., oil and gas wells) is anestablished practice frequently used to increase recovery, or to analyze production conditions.

It is useful to distinguish between types of injection, depending on the quantities ofmaterials that will be injected. Large volumes of injected materials are injected intoformations to displace formation fluids towards producing wells. The most common exampleis water flooding.

In a less extreme case, materials are introduced downhole into a well to effect treatmentwithin the well. Examples of these treatments include: (1) foaming agents to improve theefficiency of artificial lift; (2) paraffin solvents to prevent déposition of solids onto the tubing;and (3) surfactants to improve the flow characteristics of produced fluids. These types oftreatment entail modification of the well fluids themselves. Smaller quantities are needed, yetthese types of injection are typically supplied by additional tubing routed downhole from thesurface.

Still other applications require even smaller quantities of materials to be injected, suchas: (1) corrosion inhibitors to prevent or reduce corrosion of well equipment; (2) scalepreventers to prevent or reduce scaling of well equipment; and (3) tracer materials to monitorthe flow characteristics of various well sections. In these cases the quantities required aresmall enough that the materials may be supplied from a downhole réservoir, avoiding the needto run supply tubing downhole from the surface. However, the successful application oftechniques requiring controlled injection from a downhole réservoir requires that means must 13129. be provided to power and communicate with the injection equipment downhole. In existing practice this requires the use of electrical cables running from the surface to the injection modules at depth in the well. Such cables are expensive and not completely reliable, and as a conséquence are considered undesirable in current production practice.

The use of tracers to identify materials and track their flow is an established techniquein other industries, and the development of the tracer materials and the detectors has proceededto the point where the materials may be sensed in dilutions down to 1O'10, and millions ofindividually identifiable taggants are available. A représentative leading supplier of suchmaterials and détection equipment is Isotag LLC of Houston, Texas.

The use of tracers to détermine flow patterns has been applied in a wide variety ofresearch fields, such as observing biological circulatory Systems in animais and plants. It hasalso been offered as a commercial service in the oilfield, for instance as a means to analyzeinjection profiles. However the use of tracers for production in the oilfield is by exception,since existing methods require the insertion into the borehole of spécial equipment poweredand controlled using cables or hydraulic lines from the surface to depth in the well.

Ail references cited herein are incorporated by reference to the maximum extèntallowable by làw. To the extent a reference may not be fully incorporated herein, it isincorporated by reference for background purposes, and indicative of the knowledge of one ofordinary skill in the art.

CROSS-REFERENCES TO RELATED APPLICATIONS

This application daims the benefit of the following U.S. Provisional Applications, ail of whichare hereby incorporated by reference: COMMONLY OWNED AND PREVIOUSLY FILED U.S. PROVISIONAL PATENT APPLICATIONS T&K# Serial Number Title Eiling Date TH 1599 60/177,999 Toroidal Choke Inductor for Wireless Communication and Control Jan. 24,2000 TH 1600 60/178,000 Ferromagnetic Choke in Wellhead Jan. 24,2000 TH 1602 60/178,001 Controllable Gas-Lift Well and Valve Jan. 24,2000 13129. TH 1603 60/177,883 Permanent, Downhole, Wireless, Two-Way TelemetryBackbone Using Redundant Repeater, Spread Spectrum Arrays Jan. 24,2000 TH 1668 60/177,998 Petroleum Well Having Downhole Sensors, Communication, and Power Jan. 24,2000 TH 1669 60/177,997 System and Method for Fluid Flow Optimization Jan. 24,2000 TS6185 60/183,322 A Method and Apparatus for the OptimalPredistortion of an Electromagnetic Signal in a Downhole Communications System Feb. 9,2000 TH 1599x 60/186,376 Toroidal Choke Inductor for Wireless Communication and Control Mar. 2,2000 TH 1600x 60/186,380 Ferromagnetic Choke in Wellhead Mar. 2,2000 TH 1601 60/186,505 Réservoir Production Control from Intelligent Well Data Mar. 2,2000 TH 1671 60/186,504 Tracer Injection in a Production Well Mar. 2,2000 TH 1672 60/186,379 Oilwell Casing Electrical Power Pick-Off Points Mar. 2,2000 TH 1673 60/186,394 Controllable Production Well Packer Mar. 2, 2000 TH 1674 60/186,382 Use of Downhole High Pressure Gas in a Gas Lift Well Mar. 2,2000 TH 1675 60/186,503 Wireless Smart Well Casing Mar. 2,2000 TH 1677 60/186,527 Method for Downhole Power Management Using Energization from Distributed Batteries or Capacitorswith Reconfigurable Discharge Mar. 2,2000 TH 1679 60/186,393 Wireless Downhole Well Interval Inflow and Injection Control Mar. 2,2000 TH 1681 60/186,394 Focused Through-Casing Resistivity Measurement Mar. 2,2000 TH 1704 60/186,531 Downhole Rotary Hydraulic Pressure for Valve Actuation Mar. 2,2000 TH 1705 60/186,377 Wireless Downhole Measurement and Control For Optimizing Gas Lift Well and Field Performance Mar. 2,2000 TH 1722 60/186,381 Controlled Downhole Chemical Injection Mar. 2, 2000 TH 1723 60/186,378 Wireless Power and Communications Cross-Bar Switch Mar. 2,2000

The current application shares some spécification and figures with the foliowingcommonly owned and concurrently filed applications, ail of which are hereby incorporated byreference: 13129 COMMONLY OWNED AND CONCURRENTLY FILED U.S PATENT APPLICATIONS T&K# Serial Number Title Filing Date TH 1601US 09/ Réservoir Production Control from Intelligent Well Data TH 1672US 09/ Oil Well Casing Electrical Power Pick-Off Points TH 1673US 09/ Controllable Production Well Packer TH 1674US 09/ Use of Downhole High Pressure Gas in a Gas-Liâ Well TH 1675US 09/ Wireless Smart Well Casing TH 1677US 09/ Method for Downhole Power Management Using Energization from Distributed Batteries orCapacitors with Reconfigurable Discharge TH 1679US 09/ Wireless Downhole Well Interval Inflow and Injection Control TH 1681US 09/ Focused Through-Casing Resistivity Measurement TH 1704US 09/ Downhole Rotary Hydraulic Pressure for Valve Actuation TH 1705US 09/ Wireless Downhole Measurement and Control For Optimizing Gas Lift Well and Field Performance TH 1722US 09/ Controlled Downhole Chemical Injection TH 1723US 09/ Wireless Power and Communications Cross-Bar Switch 5 13129 . 5 The current application shares some spécification and figures with the following commonlyowned and previously filed applications, ail of which are hereby incorporated by reference: COMMONLY OWNED AND PREVIOUSLY FILED U.S PATENT APPLICATIONS T&K# Serial Number Title Filing Date TH 1599US 09/ Choke Inductor for Wireless Communication and Control TH1600US 09/ Induction Choke for Power Distribution in Piping Structure TH1602US 09/ Controllable Gas-Lift Well and Valve TH 1603US 09/ Permanent Downhole, Wireless, Two-Way Telemetry Backbone Using Redundant Repeater TH 1668US 09/ Petroleum Well Having Downhole Sensors, Communication, and Power TH 1669US 09/ System and Method for Fluid Flow Optimization TH 1783US 09/ Downhole Motorized Flow Control Valve TS 6185US 09/ A Method and Apparatus for the OptimalPredistortion of an Electro Magnetic Signal in a Downhole Communications System

The benefit of 35 U.S.C. § 120 is claimed for ail of the above referenced commonly ownedapplications. The applications referenced in the tables above are referred to herein as the 10 “Related Applications.”

BRIEF SUMM ARY OF THE INVENTION

The problems and needs outlined above are largely solved and met by the présentinvention. In accordance with one aspect of the présent invention, a tracer injection System foruse in a well, is provided. The tracer injection System comprises a current impédance device 15 and a downhole electrically controllable tracer injection device. The current impédance deviceis generally configured for concentric positioning about a portion of a piping structure of thewell such that when a time-varying electrical current is transmitted through and along theportion of the piping structure a voltage potential forms between one side of the currentimpédance device and another side of the current impédance device. The downhole 20 electrically controllable tracer injection device is adapted to be electrically connected to thepiping structure across the voltage potential formed by the current impédance device, adapted 13129· 6 to be powered by the electrical current, and adapted to expel a tracer material into the well inresponse to an electrical signal.

In accordance with another aspect of the présent invention, a petroleum well forproducing petroleum products, is provided. The petroleum well comprises a piping structure, asource of time-varying current, an induction choke, an electrically controllable tracer injectiondevice, and an electrical retum. The piping structure comprises a first portion, a secondportion, and an electrically conductive portion extending in and between the first and secondportions. The first and second portions are distally spaced from each other along the pipingstructure. The source of time-varying current is electrically connected to the electricallyconductive portion of the piping structure at the first portion. The induction choke is locatedabout a portion of the electrically conductive portion of the piping structure at the secondportion. The electrically controllable tracer injection device comprises two device terminais,and is located at the second portion. The electrical rètum electrically connects between theelectrically conductive portion of the piping structure at the second portion and the currentsource. A first of the device terminais is electrically connected to the electrically conductiveportion of the piping structure on a source-side of the induction choke. A second of the deviceterminais is electrically connected to the electrically conductive portion of the piping structureon an electrical-retum-side of the induction choke and/or the electrical retum.

In accordance with yet another aspect of the présent invention, a well is provided thatcomprises a piping structure, a source of time-varying current, an induction choke, a sensordevice, and an electrical retum. The piping structure comprises a first portion, a secondportion, and. an electrically conductive portion extending in and between the first and secondportions. The first and second portions are distally spaced from each other along the pipingstructure. The source of time-varying current is electrically connected to the electricallyconductive portion of the piping structure at the first portion. The induction choke locatedabout a portion of the electrically conductive portion of the piping structure at the secondportion. The sensor device comprises two device terminais and a sensor. The sensor device islocated at the second portion, and the sensor is adapted to detect a tracer material. Theelectrical retum electrically connects between the electrically conductive portion of the pipingstructure at the second portion and the current source. A first of the device terminais iselectrically connected to the electrically conductive portion of the piping structure on a source-side of the induction choke. A second of the device terminais is electrically connected to the 1312g. electrically conductive portion of the piping structure on an electrical-retum-side of the induction choke and/or the electrical retum.

In accordance with still another aspect of the présent invention, a petroleum well forproducing petroleum products, is provided. The petroleum well comprises a well casing, aproduction tubing, a source of time-varying current, a downhole tracer injection device, and adownhole induction choke. The well casing extending within a wellbore of the well. Theproduction tubing extending within the casing. The source of time-varying current located atthe surface. The current source is electrically connected to, and adapted to output a time-varying current into, the tubing and/or the casing. The downhole tracer injection devicecomprises a communications and control module, a tracer material réservoir, and anelectrically controllable tracer injector. The communications and control module is electricallyconnected to the tubing and/or the casing. The tracer injector is electrically connected to thecommunications and control module. The tracer material réservoir is in fluid communicationwith the tracer injector. The downhole induction choke is located about a portion of the tubingand/or the casing. The induction choke is adapted to route part of the electrical current throughthe communications and control module by creating a voltage potential between one side of theinduction choke and another side of the induction choke, wherein the communications andcontrol module is electrically connected across the voltage potential.

In accordance with a further aspect of the présent invention, method of producingpetroleum products from a petroleum well, is provided. The method comprises the steps of:(i) providing a piping structure extending within a wellbore of the well; (ii) providing adownhole tracer injection System for the well comprises an induction choke and an electricallycontrollable tracer injection device, the induction choke being located downhole about thepiping structure such that when a time-varying electrical current is transmitted through thepiping structure, a voltage potential forms between one side of the induction choke and anotherside of the induction choke, the electrically controllable tracer injection device being locateddownhole, the injection device being electrically connected to the piping structure across thevoltage potential formed by the induction choke such that the injection device can be poweredby the electrical current, and the injection device being adapted to expel a tracer material inresponse to an electrical signal; and (iii) controllably injecting the tracer material into adownhole flow stream within the well with the tracer injection device during production. Themethod may further comprise the steps of: (iv) providing a downhole sensor device within the 13129. well that is electrically connected to the piping structure and that can be powered by theelectrical current; (v) monitoring the flow stream at a location downstream of the tracerinjection device; (vi) detecting the tracer material within the flow stream with the sensordevice; and (vii) acting to alter the flow stream when this is désirable to meet treatment orrecovery objectives.

In accordance with a further aspect of the présent invention, method of injecting fluidsinto a formation with a well, is provided. The method comprises the steps of: (i) providing apiping structure extending within a wellbore of the well; (ii) providing a downhole sensorSystem for the well comprises an induction choke and a sensor device, the induction chokebeing located downhole about the piping structure such that when a time-varying electricalcurrent is transmitted through the piping structure, a voltage potential forms between one sideof the induction choke and another side of the induction choke, the sensor device being locateddownhole, the sensor device being electrically connected to the piping structure across thevoltage potential formed by the induction choke such that the sensor device can be powered bythe electrical current, and the sensor device comprises a sensor adapted to detect a tracermaterial; and (iii) detecting the tracer material within a flow stream of the well with the sensordevice during fluid injection operation. The method may further comprise the steps of: (iv)providing a tracer injection device for said well at the surface; and (v) injecting said tracermaterial into said flow stream going into said well with said tracer injection device.

BRIEF DESCRIPTION OF THE DRAWINGS

Other objects and advantages of the invention will become apparent upon reading thefollowing detailed description and upon referencing the accompanying drawings, in which: FIG. 1 is a schematic showing a petroleum production well in accordance with apreferred embodiment of the présent invention; FIG. 2A is schematic of an upper portion of a petroleum well in accordance withanother preferred embodiment of the présent invention; FIG. 2B is schematic of an upper portion of a petroleum well in accordance with yetanother preferred embodiment of the présent invention; FIG. 3 is an enlarged view of a downhole portion of the well in FIG. 1; 13129- FIG. 4 is a simplified electrical schematic of the electrical circuit formed by the well of FIG. 1; FIGs. 5A-5D are schematics of various tracer injector and tracer material réservoirembodiments for a downhole electrically controllable tracer injection device in accordancewith the présent invention; FIG. 6 is a schematic of a sensor device in a petroleum well in accordance with theprésent invention; FIGs. 7A-7E are schematics of uniform inflow and injection profiles for various wellconfigurations; FIG. 8 is a plot illustrating fluid flow fines in a circular pipe with laminar flow in thecase where fluids enter the pipe uniformly at its wall along the length of the pipe; FIGs. 9A-9J are simplified schematics illustrating example various configurations fortracer injection device and sensor device placement within a variety of well configurations; FIG. 10 graphs normalized arrivai time on the ordinate as a fonction of normalizeddepth on the abscissa for a simulation of inflow using 100 inflow zones; FIG. 11 graphs normalized arrivai time on the ordinate as a fonction of normalizeddepth on the abscissa for a simulation of inflow using 1000 inflow zones; FIG. 12 defines the injectivity profile of an illustrative injection well by graphinginjectivity profile on the ordinate as a function of depth on the abscissa; FIG. 13 graphs the tracer transit time per unit length of the illustrative injection welldefined in FIG. 12 by depicting transit time on the ordinate as a fonction of depth on theabscissa; FIG. 14 graphs the arrivai time of tracer in the illustrative injection well defined byFIG. 12 by depicting arrivai time on the ordinate as a fonction of depth on the abscissa; FIG. 15 compares calculated and actual injection rates as a fonction of depth in theillustrative injection well defined by FIG. 12 by graphing injection rate on the ordinate as afonction of depth on the abscissa; 13129· 10 FIG. 16 defines four illustrative cases of production wells by graphing cumulativeinflow on the ordinate as a fonction of depth on the abscissa; FIG. 17 graphs normalized arrivai time of an injected tracer on the ordinate as afonction of depth for the four illustrative cases of production Wells defined in FIG. 16; FIG. 18 graphs normalized arrivai time of an injected tracer relative to a uniforminjection rate case on the ordinate as a fonction of depth for the four illustrative cases ofproduction wells defined in FIG. 16; FIG. 19 graphs the relative concentration of tracer puises on the ordinate as a fonctionof arrivai time on the abscissa for the case of uniform inflow over a producing interval; FIG. 20 graphs the relative concentration of tracer puises on the ordinate as a fonctionof arrivai time on the abscissa for one illustrative case of non-uniform inflow over a producinginterval; FIG. 21 graphs the relative concentration of tracer puises on the ordinate as a fonctionof arrivai time on the abscissa for a second illustrative case of non-uniform inflow over aproducing interval; FIG. 22 graphs the relative concentration of tracer puises on the ordinate as a fonctionof arrivai time on the abscissa for a third illustrative case of non-uniform inflow over aproducing interval; FIG. 23 graphs cumulative pressure drop along tubing on the ordinate as a fonction ofdistance along a horizontal well on the abscissa for various illustrative cases of différencesbetween réservoir pressure and well toe pressure in horizontal completion wells; and FIG. 24 graphs relative inflow rates per unit length on the ordinate as a fonction ofdistance along. a horizontal well on the abscissa for various' illustrative cases of différencesbetween réservoir pressure and well toe pressure in a horizontal completion well.

DETAILED DESCRIPTION OF THE INVENTION

Referring now to the drawings, wherein like reference numbers are used herein todesignate like éléments throughout the various views, preferred embodiments of the présent 13129· 11 invention are illustrated and further described. The figures are not necessarily drawn to scale,and in some instances the drawings hâve been exaggerated and/or simplified in places forillustrative purposes only. One of ordinary skill in the art will appreciate the many possibleapplications and variations of the présent invention based on the following examples ofpossible embodiments of the présent invention, as well as based on those embodimentsillustrated and discussed in the Related Applications, which are incorporated by referenceherein to the maximum extent allowed by law.

As used in the présent application, a “piping structure” can be one single pipe, a tubingstring, a well casing, a pumping rod, a sériés of interconnected pipes, rods, rails, trusses,lattices, supports, a branch or latéral extension of a well, a network of interconnected pipes, orother similar structures known to one of ordinary skill in the art. A preferred embodimentmakes use of the invention in the context of a petroleum well where the piping structurecomprises tubular, metallic, electrically-conductive pipe or tubing strings, but the invention isnot so limited. For the présent invention, at least a portion of the piping structure needs to beelectrically conductive, such electrically conductive portion may be the entire piping structure(e.g., Steel pipes, copper pipes) or a longitudinal extending electrically conductive portioncombined with a longitudinally extending non-conductive portion. In other words, anelectrically conductive piping structure is one that provides an electrical conducting path froma first portion where a power source is electrically connected to a second portion where adevice and/or electrical retum is electrically connected. The piping structure will typically beconventional round métal tubing, but the cross-section geometry of the piping structure, or anyportion thereof, can vary in shape (e.g., round, rectangular, square, oval) and size (e.g., length,diameter, wall thickness) along any portion of the piping structure. Hence, a piping structuremust hâve an electrically conductive portion extending from a first portion of the pipingstructure to a second portion of the piping structure, wherein the first portion is distally spacedfrom the second portion along the piping structure.

The terms “first portion” and “second portion” as used herein are each definedgenerally to call out a portion, section, or région of a piping structure that may or may notextend along the piping structure, that can be located at any chosen place along the pipingstructure, and that may or may not encompass the most proximate ends of the piping structure.

The term “modem” is used herein to generically refer to any communications devicefor transmitting and/or receiving electrical communication signais via an electrical conductor 13129· 12 (e.g., métal). Hence, the term “modem” as used herein is not limited to the acronym for amodulator (device that converts a voice or data signal into a form that can betransmitted)/demodulator (a device that recovers an original signal after it has modulated ahigh ftequency carrier). Also, the term “modem” as used herein is not limited to conventionalcomputer modems that convert digital signais to analog signais and vice versa (e.g., to senddigital data signais over the analog Public Switched Téléphoné Network). For example, if asensor outputs measurements in an analog format, then such measurements may only need tobe modulated (e.g., spread spectrum modulation) and transmitted--hence no analog/digitalconversion needed. As another example, a relay/slave modem or communication device mayonly need to identify, filter, amplify, and/or retransmit a signal received.

The term “valve” as used herein generally refers to any device that fonctions to regulatethe flow of a fluid. Examples of valves include, but are not limited to, bellows-type gas-liftvalves and controllable gas-lift valves, each of which may be used to regulate the flow of liftgas into a tubing string of a well. The internai and/or extemal workings of valves can varygreatly, and in the présent application, it is not intended to limit the valves described to anyparticular configuration, so long as the valve fonctions to regulate flow. Some of the varioustypes of flow regulating mechanisms include, but are not limited to, bail valve configurations,needle valve configurations, gâte valve configurations, and cage valve configurations. Themethods of installation for valves discussed in the présent application can vary widely.

The term “electrically controllable valve” as used herein generally refers to a “valve”(as just described) that can be opened, closed, adjusted, altered, or throttled continuously inresponse to an electrical control signal (e.g., signal ftom a surface computer or ftom adownhole electronic controller module). The mechanism that actually moves the valveposition can comprise, but is not limited to: an electric motor; an electric servo; an electricsolenoid; an electric switch; a hydraulic actuator controlled by at least one electrical servo,electrical motor, electrical switch, electric solenoid, or combinations thereof; a pneumaticactuator controlled by at least one electrical servo, electrical motor, electrical switch, electricsolenoid, or combinations thereof; or a spring biased device in combination with at least oneelectrical servo, electrical motor, electrical switch, electric solenoid, or combinations thereof.An “electrically controllable valve” may or may not include a position feedback sensor forproviding a feedback signal corresponding to the actual position of the valve. 13129· 13

The terni “sensor” as used herein refers to any device that detects, détermines,monitors, records, or otherwise senses the absolute value of or a change in a physical quantity.A sensor as described herein can be used to measure physical quantities including, but notlimited to: température, pressure (both absolute and differential), flow rate, seismic data,acoustic data, pH level, salinity levels, valve positions, volume, or almost any other physicaldata. A sensor as described herein also can be used to detect the presence or concentration of atracer material within a flow stream.

The phrase “at the surface” as used herein refers to a location that is above about fiflyfeet deep within the Earth. In other words, the phrase “at the surface” does not necessarilymean sitting on the ground at ground level, but is used more broadly herein to refer to alocation that is often easily or conveniently accessible at a wellhead where people may beworking. For example, “at the surface” can be on a table in a work shed that is located on theground at the well platform, it can be on an océan floor or a lake floor, it can be on a deep-seaoil rig platform, or it can be on the lOOth floor of a building. Also, the term “surface” may beused herein as an adjective to designate a location of a component or région that is located “atthe surface.” For example, as used herein, a “surface” computer would be a computer located“at the surface.”

The term “downhole” as used herein refers to a location or position below about fiftyfeet deep within the Earth. In other words, “downhole” is used broadly herein to refer to alocation that is often not easily or conveniently accessible from a wellhead where people maybe working. For example in a petroleum well, a “downhole” location is often at or proximateto a subsurface petroleum production zone, irrespective of whether the production zone isaccessed vertically, horizontally, latéral, or any other angle therebetween. Also, the term“downhole” is used herein as an adjective describing the location of a component or région.For example, a “downhole” device in a well would be a device located “downhole,” asopposed to being located “at the surface.”

As used in the présent application, "wireless" means the absence of a conventional, insulatedwire conductor e.g. extending from a downhole device to the surface. Using the tubing and/orcasing as a conductor is considered "wireless."

Similarly, in accordance with conventional terminology of oilfield practice, thedescriptors “upper,” “lower,” “uphole,” and “downhole” are relative and refer to distance along 13129· 14 hole depth from the surface, which in deviâted or horizontal wells may or may not accord withvertical élévation measured with respect to a survey datum. FIG. 1 is a schematic showing a petroleum production well 20 in accordance with apreferred embodiment of the présent invention. The well 20 has a vertical section 22 and alatéral section 26. The well has a well casing 30 extending within the wellbore and through aformation 32, and a production tubing 40 extends within the well casing for conveying fluidsfrom downhole to the surface during production. Hence, the petroleum production well 20shown in FIG. 1 is similar to existing practice in well construction, but with the incorporationof the présent invention.

The vertical section 22 in this embodiment incorporâtes a gas-lift valve 42 and an upperpacker 44 to provide artificial lift for fluids within the tubing 40. However, in alternative,other ways of providing artificial lift may be incorporated to form other possible embodiments(e.g., rod pumping). Also, the vertical portion 22 can further vary to form many other possibleembodiments. For example in an enhanced form, the vertical portion 22 may incorporate oneor more electrically controllable gas-lift valves, one or more additional induction chokes,and/or one or more controllable packers comprising electrically controllable packer valves, asfurther described in the Related Applications.

The latéral section 26 of the well 20 extends through a petroleum production zone 48(e.g., oil zone) of the formation 32. The casing 30 in the latéral section 26 is perforated at theproduction zone 48 to allow fluids from the production zone 48 to flow into the casing. FIG. 1shows only one latéral section 26, but there can be many latéral branches of the well 20. Thewell configuration typically dépends, at least in part, on the layout of the production zones fora given formation.

Part of the tubing 40 extends into the latéral section 26 and terminâtes with a closed end52 past the production zone 48. The position of the tubing end 52 within the casing 30 ismaintained by a latéral packer 54, which is a conventional packer. The tubing 40 has aperforated section 56 at the production zone 48 for fluid intake from the production zone 48.In other embodiments (not shown), the tubing 40 may continue beyond the production zone 48(e.g., to other production zones), or the tubing 40 may terminate with an open end for fluidintake. 13129- 15

An electrically controllable downhole tracer injection device 60 is connected inline onthe tubing 40 within the latéral section 26 and forms part of the production tubing assembly.The injection device is located upstream of the production zone 48 near the vertical section forease of placement. However, in other embodiments, the injection device 60 may be locatedfurther within a latéral section. An advantage of placing the injection device 60 proximate tothe tubing intake 56 at the production zone 48 is that it a désirable location for injecting atracer material. But when the injection device is remotely located relative to the tubing intake56, as shown in FIG. 1, a tracer material can be injected into the tubing intake 56 at theproduction zone 48 using a nozzle extension tube 70. The nozzle extension tube 70 thusprovides a way to inject a tracer material into a flow stream at a location remote from theinjection device 60. Expelling a tracer material at a location remote from (e.g., up stream of)the injection device 60, via the nozzle extension tube 70, allows for a sensor adapted to detectthe tracer material to be located at or within the injection device 60. (Such a sensor is 108 asshown in FIG. 3). In other possible embodiments, the injection device 60 may be adapted tocontrollably inject a tracer material at a location outside of the tubing 40 (e.g., directly into theproducing zone 48, or into an annular space 62 within the casing 30). Therefore, anelectrically controllable downhole tracer injection device 60 may be placed in any downholelocation within a well where it is needed.

An electrical circuit is formed using various components of the well 20. Power for theelectrical components of the injection device 60 is provided from the surface using the tubing40 and casing 30 as electrical conductors. Hence, in a preferred embodiment, the tubing 40acts as a piping structure and the casing 30 acts as an electrical retum to form an electricalcircuit in the well 20. Also, the tubing 40 and casing 30 are used as electrical conductors forcommunication signais between the surface (e.g., a surface computer System 64) and thedownhole electrical components within the electrically controllable downhole tracer injectiondevice 60,

In FIG. 1, a surface computer system 64 comprises a master modem 66 and a source oftime-varying current 68. But, as will be clear to one of ordinary skill in the art, the surfaceequipment can vary. A first computer terminal 71 of the surface computer system 64 iselectrically connected to the tubing 40 at the surface, and imparts time-varying electricalcurrent into the tubing 40 when power to and/or communications with the downhole devices isneeded. The current source 68 provides the electrical current, which carries power and 16 communication signais downhole. The time-varying electrical current is preferably alternatingcurrent (AC), but it can also be a varying direct current (DC). The communication signais canbe generated by the master modem 66 and embedded within the current produced by the source68. Preferably, the communication signal is a spread spectrum signal, but other forms ofmodulation or pre-distortion can be used in alternative. A first induction choke 74 is located about the tubing in the vertical section 22 belowthe location where the latéral section 26 extends from the vertical section. A second inductionchoke 90 is located about the tubing 40 within the latéral section 26 proximate to the injectiondevice 60. The induction chokes 74, 90 comprise a ferromagnetic material and are unpowered.Because the chokes 74, 90 are located about the tubing 40, each choke acts as a large inductorto AC in the well circuit formed by the tubing 40 and casing-30. As described in further detailin the Related Applications, the chokes 74, 90 fonction based on their size (mass), geometry,and magnetic properties.

An insulated tubing joint 76 is incorporated at the wellhead to electrically insulate thetubing 40 from casing 30. The first computer terminal 71 from the current source 68 passesthrough an insulated seal 77 at the hanger 88 and electrically connects to the tubing 40 belowthe insulated tubing joint 76. A second computer terminal 72 of the surface computer System64 is electrically connected to the casing 30 at the surface. Thus, the insulators 79 of thetubing joint 76 prevent a short between the tubing 40 and casing 30 at the surface. Inalternative to (or in addition to) the insulated tubing joint 76, a third induction choke 176 (seeFIG. 2A) can be placed about the tubing 40 above the electrical connection location for thefirst computer terminal 71 to the tubing, and/or the hanger 88 may be an insulated hanger 276(see FIG. 2B) having insulators 277 to electrically insulate the tubing 40 from the casing 30.

The latéral packer 54 at the tubing end 52 within the latéral section 26 provides anelectrical connection between the tubing 40 and the casing 30 downhole beyond the secondchoke 90. A lower packer 78 in the vertical section 22, which is also a convéntional packer,provides an electrical connection between the tubing 40 and the casing 30 downhole below thefirst induction choke 74. The upper packer 44 of the vertical section 22 has an electricalinsulator 79 to prevent an electrical short between the tubing 40 and the casing 30 at the upperpacker. Also, various centralizers (not shown) having electrical insulators to prevent shortsbetween the tubing 40 and casing 30 can be incorporated as needed throughout the well 20.Such electrical insulation of the upper packer 44 or a centralizer may be achieved in various 13129· 17 5 ways apparent to one of ordinary skill in the art. The upper and lower packers 44, 78 providehydraulic isolation between the main wellbore of the vertical section 22 and the latéralwellbore of the latéral section 26. FIG. 3 is an enlarged view showing a portion of the latéral section 26 of FIG. 1 with theelectrically controllable downhole tracer injection device 60 therein. The injection device 60 10 comprises a communications and control module 80, a tracer material réservoir 82, anelectrically controllable tracer injector 84, and a sensor 108. Preferably, the components of anelectrically controllable downhole tracer injection device 60 are ail contained in a single,sealed tubing pod 86 together as one module for ease of handling and installation, as well as toprotect the components from the surrounding environment. However, in other embodiments of 15 the présent invention, the components of an electrically controllable downhole tracer injectiondevice 60 can be separate (i.e., no tubing pod 86) or combined in other combinations. A firstdevice terminal 91 of the injection device 60 electrically connects between the tubing 40 on asource-side 94 of the second induction choke 90 and the communications and control module80. A second device terminal 92 of the injection device 60 electrically connects between the 20 tubing 40 on an electrical-retum-side 96 of the second induction choke 90 and thecommunications and control module 80. Although the latéral packer 54 provides an electricalconnection between the tubing 40 on the electrical-retum-side 96 of the second induction 90and the casing 30, the electrical connection between the tubing 40 and the well casing 30 alsocan be accomplished in numerous ways, some of which can be seen in the Related 25 Applications, including (but not limited to): another packer (conventional or controllable); aconductive centralizer; conductive fluid in the annulus between the tubing and the well casing;or any combination thereof. FIG. 4 is a simplified electrical sçhematic illustrating the electrical circuit formed in thewell 20 of FIG. 1. In operation, and referring to both FIG.l and FIG. 4, power and/or 30 communications are imparted into the tubing 40 at the surface via the first computer terminal71 below the insulated tubing joint 76. Time-varying current is hindered from flowing fromthe tubing 40 to the casing 30 via the hanger 88 due to the insulators 79 of the insulated tubingjoint 76. However, the time-varying current flows freely along the tubing 40 until theinduction chokes 74, 90 are encountered. The first induction choke 74 provides a large 35 inductance that impedes most of the current from flowing through the tubing 40 at the firstinduction choke. Similarly, the second induction choke 90 provides a large inductance that 13129- 18 impedes most of the current ftom flowing through the tubing 40 at the second induction choke.A voltage potential forms between the tubing 40 and casing 30 due to the induction chokes 74,90. The voltage potential also forms between the tubing 40 on the source-side 94 of the secondinduction choke 90 and the tubing 40 on the electrical-retum-side 96 of the second inductionchoke 90. Because the communications and control module 80 is electrically connected acrossthe voltage potential, most of the current imparted into the tubing 40 that is not lost along theway is routed through the communications and control module 80, which distributes and/ordécodés the power and/or communications for the injection device 60. Aller passing throughthe injection device 60, the current retums to the surface computer System 64 via the latéralpacker 54 and the casing 30. When the current is AC, the flow of the current just describedwill also be reversed through the well 20 along the same path.

Other alternative ways to develop an electrical circuit using a piping structure of a welland at least one induction choke are described in the Related Applications, many of which canbe applied in conjunction with the présent invention to provide power and/or communicationsto the electrically powered downhole devices and to form other embodiments of the présentinvention.

Referring to FIG. 3 again, the communications and control module 80 comprises anindividually addressable modem 100, power conditioning circuits 102, a control interface 104,and a sensors interface 106. Because the modem 100 of the downhole injection device 60 isindividually addressable, more than one downhole device may be installed and operatedindependently of others.

In FIG. 3, the electrically controllable tracer injector 84 is electrically connected to thecommunications and control module 80, and thus obtains power and/or communications fromthe surface computer System 64 via the communications and control module 80. The tracermaterial réservoir 82 is in fluid communication with the tracer injector 84. The tracer materialréservoir 82 is a self-contained réservoir that stores and supplies tracer materials for injectinginto the flow stream by the tracer injector 84. The tracer material réservoir 82 of FIG. 3 is notsupplied by a tracer material supply tubing (not shown) extending from the surface, but inother embodiments it may be. Hence, the size of the tracer material réservoir 82 may vary,depending on the volume of tracer materials needed for the injecting into the well 20. Thetracer injector 84 of a preferred embodiment comprises an electric motor 110, a screwmechanism 112, and a nozzle 114. The electric motor 110 is electrically connected to and 19 1 29 receives motion command signais from the communications and control module 80. Thenozzle extension tube 70 extends from the nozzle 114 into an interior 116 of the tubing at thetubing intake 56 (farther upstream), and provides a fluid passageway from the tracer materialréservoir 82 to the tubing interior 116. The screw mechanism 112 is mechanically coupled tothe electric motor 110. The screw mechanism 112 is used to drive tracer materials out of theréservoir 82 and into the tubing interior 116, via the nozzle 114 and via the nozzle extensiontube 70, in response to a rotational motion of the electric motor 110. Preferably the electricmotor 110 is a stepper motor, and thus provides tracer material injection in incrémentalamounts.

In operation, the fluid stream from the production zone 48 passes around the tracerinjection device 60 as it flows through the tubing 40 to the surface. Commands from thesurface computer System 64 are transmitted downhole and received by the modem 100 of thecommunications and control module 80. Within the injection device 60 the commands aredecoded and passed from the modem 100 to the control inter&ce 104. The control interface104 then commands the electric motor 110 to operate and inject the specifîed quantity of tracermaterials from the réservoir 82 into the fluid flow stream in the tubing 40. Hence, the tracerinjection device 60 controllably injects a tracer material into the fluid stream flowing withinthe tubing 40, as needed or as desired, in response to commands from the surface computerSystem 64 via the communications and control module 80.

The tracer injection device 60 of FIG. 3 also comprises sensors 108. At least one of thesensors 108 is adapted to detect the presence and/or concentration of a tracer material withinthe flow stream passing through the tubing 40. The sensors 108 are electrically connected tothe communications and control module 80 via the sensor interface 106. The tracer injectiondevice 60 may also fiirther comprise sensors to make other measurements, such as flow rate,température, or pressure. The data from the sensors 108 are encoded within thecommunications and control module 80 and can be transmitted to the surface computer System64 by the modem 100. Thus during operation, when tracer material is injected into the tubinginterior 116 upstream by the tracer injector 84 (via the nozzle extension tube 70), the sensors108 detect the tracer as it passes within the flow stream. By measuring the arrivai time (timefrom injection to détection) and/or the concentration of tracer detected, the characteristics ofthe flow stream can be determined, as fiirther detailed below herein. 20 13)29 5 As will be apparent to one of ordinary skill in the art, the mechanical and electrical arrangement and configuration of the components within the electrically controllable tracerinjection device 60 can vary while still performing the same function—providing electricallycontrollable tracer injection downhole. For example, the contents of a communications andcontrol module 80 may be as simple as a wire connecter terminal for distributing electrical 1Q connections from the tubing 40, or it may be very complex comprising (but not limited to) amodem, a rechargeable battery, a power transformer, a microprocessor, a memory storagedevice, a data acquisition card, and a motion control card. FIGs. 5A-5D illustrate some possible variations of the tracer material réservoir 82 andtracer injecter 84 that may be incorporated into the présent invention to form other possible 15 embodiments. In FIGs. 5A-5D, a nozzle extension tube 70 is not incorporated. Thus, thetracer injection devices show in FIGs. 5A-5D are adapted for being located at the locationwhere the tracer injection is desired. However, a nozzle extension tube also can beincorporated into any of the embodiments shown in FIGs. 5A-5D.

In FIG. 5A, the tracer injecter 84 comprises a pressurized gas réservoir 118, a pressure 20 regulator 120, an electrically controllable valve 122, and a nozzle 114. The pressurized gasréservoir 118 is fluidly connected to the réservoir 82 via the pressure regulator 120, and thussupplies a generally constant gas pressure to the réservoir. The tracer material réservoir 82 hasa bladder 124 therein that contains the tracer materials. The pressure regulator 120 régulâtesthe passage of pressurized gas supplied from the pressurized gas réservoir 118 into the 25 réservoir 82 but outside of the bladder 124. However, the pressure regulator 120 may besubstituted with an electrically controllable valve. The pressurized gas exerts pressure on thebladder 124 and thus on the tracer materials therein, The electrically controllable valve 122régulâtes and Controls the passage of the tracer materials through the nozzle 114 and into thetubing interior 116. Because the tracer materials inside the bladder 124 are pressurized by the 30 gas from the pressurized gas réservoir 118, the tracer materials are forced out of the nozzle 114when the electrically controllable valve 122 is opened.

In FIG. 5B, the tracer material réservoir 82 is divided into two volumes 126, 128 by abladder 124, which acts a separator between the two volumes 126, 128. A first volume 126within the bladder 124 contains the tracer material, and a second volume 128 within the tracer 35 material réservoir 82 but outside of the bladder contains a pressurized gas. Hence, theréservoir 82 is precharged and the pressurized gas exerts pressure on the tracer materials within 13129· 21 the bladder 124. The tracer injector 84 comprises an electrically controllable valve 122 and anozzle 114. The electrically controllable valve 122 is electrically connected to and controlledby the communications and control module 80. The electrically controllable valve 122régulâtes and Controls the passage of the tracer materials through the nozzle 114 and into thetubing interior 116. The tracer materials are forced out of the nozzle 114 due to the gaspressure when the electrically controllable valve 122 is opened.

The embodiment shown in FIG. 5C is similar that of FIG. 5B, but the pressure on thebladder 124 is provided by a spring member 130. Also in FIG. 5C, the bladder may not beneeded if there is movable seal (e.g., sealed piston) between the spring member 130 and thetracer materials within the réservoir 82. One of ordinary skill in the art will see that there canbe many variations on the mechanical design of the tracer inj ector 84 and on the use of a springmember to provide pressure on the tracer materials.

In FIG. 5D, the tracer material réservoir 82 has a bladder 124 containing a tracermaterial. 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 iselectrically connected to and controlled by the communications and control module 80. Theone-way valve 136 prevents backflow into the pump 134 and bladder 124. The pump 134drives tracer materials out of the bladder 124, through the one-way valve 136, out of the nozzle114, and into the tubing interior 116. Hence, the use of the tracer injector 84 of FIG. 5D maybe advantageous in a case where the tracer material réservoir 82 is arbitrarily shaped tomaximize the volume of tracer materials held therein for a given configuration because theréservoir configuration is not dépendent on tracer injector 84 configuration implemented.

Thus, as the examples in FIGs. 5A-5D illustrate, there are many possible variations forthe tracer material réservoir 82 and tracer injector 84. One of ordinary skill in the art will seethat there can be many more variations for performing the functions of storing tracer materialsdownhole in combination with controllably injecting the tracer materials into the tubinginterior 116 in response to an electrical signal. Variations (not shown) on the tracer injector 84may further include (but are not limited to): a venturi tube at the nozzle; pressure on thebladder provided by a turbo device that extracts rotational energy from the fluid flow withinthe tubing; extracting pressure from other régions of the formation routed via a tubing; anypossible combination of the parts of FIGs. 5A-5D; or any combination thereof. 13129 · 22

The tracer injection device 60 may not inject tracer materials into the tubing interior116. In other words, a tracer injection device may be adapted to controllably inject a tracermaterials into the formation 32, into the casing 30, or directly into the production zone 48.Also, a single tracer injection device 60 may be adapted to expel multiple tracer materials (i.e.,different tracer identifiers or signatures), such as by having multiple tracer material réservoirs82 and/or multiple tracer injectors 84. À single tracer injection device 60 may be adapted toinject tracer materials into a well at numerous locations, for example, by having multiplenozzle extension tubes 70 extending to multiple locations.

The tracer injection device 60 may further comprise other components to form otherpossible embodiments of the présent invention, including (but not limited to): other sensors , amodem, a microprocessor, a logic circuit, an electrically· controllable tubing valve, multipletracer material réservoirs (which may contain different tracers), multiple tracer injectors (whichmay be used to expel multiple tracer materials to multiple locations), or any combinationthereof. The tracer material injected may be a solid, liquid, gas, or mixtures thereof. Thetracer material injected may be a single component, multiple components, or a complexformulation. Furthermore, there can be multiple controllable tracer injection devices for one ormore latéral sections, each of which may be independently addressable, addressable in groups,or uniformly addressable from the surface computer System 64. In alternative to beingcontrolled by the surface computer System 64, the downhole electrically controllable injectiondevice 60 can be controlled by electronics therein or by another downhole device. Likewise,the downhole electrically controllable injection device 60 may control and/or communicatewith other downhole devices. In an enhanced form of an electrically controllable tracerinjection device 60, it comprises at least one additional sensor, each adapted to measure aphysical quality such as (but not limited to): absoîute pressure, differential pressure, fluiddensity, fluid viscosity, acoustic transmission or reflection properties, température, or Chemicalmake-up. Also, a tracer injection device 60 may not contain any sensors (i.e., no sensor 108),and the sensor 108 for detecting a tracer material may be separate and remotely located (e.g.,downstream, or at the surface) relative to the tracer injection device 60. FIG. 6 illustrâtes an example of a separate, downhole sensor device 140 having its owncorresponding induction choke 142 located proximate thereto for routing power and/orcommunications for the sensor device. The sensor device 140 comprises a sensor 108, acommunications and control module 144 and a modem 146. Thus, data acquired by the sensor 13129· 23 device 140 can be transmitted to a surface computer System or another downhole device usingthe tubing 40 and/or casing 30 as an electrical conductor.

In still another method of operation, the tracers may be generated downhole by the useof electrical currents, thereby obviating the need for a downhole Chemical réservoir. Thismethod offers the opportunity of an ongoing supply of tracer throughout the well life. Forexample, changes in pH of a natural brine can be effected by an electrolytic cell whichdécomposés the salts into chlorine gas and the métal hydroxide. Typically, sodium chloride isdecomposed into chlorine gas and the métal hydroxide. A pH sensor may be used to detectsuch a puise of high pH water that is generated in line or is collected and released as a slug.Another potentially useful electrically driven Chemical reaction is the génération of ozone suchas is used in devices for control of biological activity in swimming pools and water supplySystems. In another application, a solid material may be placed in the well and made to enterinto the well fluid stream by a controlled dissolution that is achieved by a controlled puise ofelectrical energy. The dissolved material is preferably unique to the fluid environment of thewell, thereby allowing détection at low concentrations. An example of such a solid material isa metallic zinc element. Commercially available analytical devices offer détection of manyother compounds that can be electrically generated by those skilled in the art.

Upon review of the Related Applications, one of ordinary skill in the art will see thatthere can also be other electrically controllable downhole devices, as well as numerousinduction chokes, further included in a well to form other possible embodiments of the présentinvention. Such other electrically controllable downhole devices include (but are not limitedto): one or more controllable packers having electrically controllable packer valves, one ormore electrically controllable gas-lift valves; one or more modems, one or more sensors; amicroprocessor; a logic circuit; one or more electrically controllable tubing valves to controlflow from various latéral branches; and other electronic components as needed.

In use, a number of applications of the présent invention arise, both in conventionalwells and in complex future designs. For example, in vertical wells completed over longintervals, the inflow profiles of production wells are of interest in order to correct uneveninflow and thereby allow uniform déplétion of the entire formation. Similarly, floodingoperations in long interval complétions dépend upon attainment of uniform injection profiles inorder to sweep out the whole zone. FIGs. 7A and 7B schematically illustrate uniform inflowand uniform injection profiles, respectively, for a vertical well. 13129· 24

In wells with long horizontal complétions, the maintenance of uniform profiles is lessdépendent on différences in permeabilities of geological layers as it is on the pressure gradientsalong the wells. These pressure gradients tend to favor high production rates near the well heel( i.e., the horizontal section nearest the vertical part of the well.) FIGs. 7C and 7Dschematically illustrate uniform inflow and injection profiles, respectfully, for a longhorizontal completion.

Another application is the use of tracers to differentiate production in wells withmultiple latéral branches. In these wells it is important to understand which latéral isproducing excessive water or which latéral is already depleted. FIG. 7E schematicallyillustrâtes a uniform inflow profile for multiple laterals. Hence, FIGs. 7A-7E illustrate thedésirable flow profiles for just a few of the many possible well configurations, which arehighly dépendent on the naturel layout of production zones in a giveh formation.

The movement of fluids in a subsurface well can be monitored by injecting tracers atvarious positions and observing the time of arrivai and the dilution from fluids that enter thewell downstream of the tracer injection point. As described above, the tracers are injected intoa flow stream from a storage réservoir 82 within an injection device 60. But in alternative, atracer may be generated within the injection device 60 by electrical methods.

The movement of a slug of tracer injected into a well stream is dépendent on the degreeof mixing during its transport along the well. In the case of simple flow in a pipe, the velocityprofile varies with radial position, so that fluids move somewhat faster at the center of the pipethan at the wall. If flow is in the laminar région (that is, at low rates) the shape of the velocityprofile is parabolic, and for the case of no-slip at the wall, a tracer would be scattered over thelength of the flow. In practice, because pipe walls are rough and flow is fast, turbulent flowusually occurs. The turbulence mixes the fluids so that tracers are more uniformly transportedand generally reflect the average velocity of flow in the pipe.

In production or injection wells completed with perforated or screened liners, inflow offluids occurs through the pipe wall into the flow stream along the well. In this case, flow of afluid that enters the well at the wall at various positions along the open interval is morecomplex. Examples given below apply to flow in either vertical or horizontal wells, however,a vertical well is used to demonstrate a laminar flow case in which inflow occurs along an openinterval. 13129- 25

Assuming flow is laminar and no mixing occurs across flow streamlines, the fluidentering the bottom of the open interval initially fills the entire cross-section of the hole.Further uphole, additional inflow of fluids constricts the initial fluid that entered at the bottomand drives it radially inward. At the top of the open interval the last fluid that entered will bein the radial région near the wall and the initial fluid that entered at the bottom will be at thecenter of the well. Thus, tracer sensors should be placed such that they intercept the tracers inthe passing stream. The use of a turbulator (not shown) immediately upstream of the sensor tomix the tracer stream into the bulk flow stream may be advantageous for this purpose.

Referring again to FIG. 7A, which illustrâtes the flow pattern for a fluid flowing at auniform rate into a circular pipe, this flow pattern may be constructed with the followingmodel:

Assumptions: 1) Uniform inflow of fluids into the well; and 2) Uniform velocity profile within the well.

This assumption is somewhat contrary to the expectation of parabolic velocity profilesfor flow in a pipe with no-slip at the wall. However, in this case in which fluids are entering atthe wall, the flow more closely approaches plug flow. Définitions: q = inflow rate / unit length of interval [ barrels / day / fl ] L = heightabove bottom of open interval [fl]

Lj = fluid (tracer) inflow point above the bottom of open interval [ fl ]

Lo = total height of open interval [ ô ] f = fraction of well area occupied by flow from the interval from 0 to Lv = velocity of flow at height L [ fl / day ]r0 - radius of well [ ft ] r = radius of flow of fluids in well that entered well below L [fl ] 13129· 26

Now consider fluids entering the well at sonie height, above the bottom of the well.At heights above this ( L equal to or greater than Li ) the fraction of the cross-sectional wellarea occupied by the fluids which entered below Lj is: f = qLj/qL = νπΓ2/νπτ02 (1)

Therefore, L=Li(r0/r)2 (2)

The plot in FIG. 8 shows the streamlines of flow in a well when fluids enter the welluniformly with depth. When flow is turbulent, as is the case in most wells, the streamlines aremixed. Under these conditions, the FIG. 8 plot represents the fraction of flow at a given depth(rather than the radial position) that is made up of fluids that entered the well below that depth.

To dérivé information on fluid movement in wells it is necessary to understand the timeof arrivai and the concentration of tracers that may be injected at various positions in theflowing stream. Use of the présent invention provides ways to controllably inject a tracermaterial at virtually any downhole location and/or to detect the presence of or concentration Ofthe tracer material with in the flow stream at virtually any downhole location. FIGs. 9A-9Jprovide just of few examples of the many possible placements of tracer injection devices 60(which may or may not include a sensor 108) and/or sensor devices 140 in a production orinjection well. Again, the désirable configuration of a well is typically dépendent on the layoutof production zones 48 in a formation 32. The downhole tracer injection devices 60 anddownhole sensor devices 140 may or may not be permanently installed. Permanent downholedevices are preferred due to the expense and time required to add, remove, modify, replenish,or replace a downhole device. The présent invention makes it possible to install downholedevices permanently because, among other things, the présent invention provides innovativeways to provide power and/or communications to such permanent downhole devices. FIG. 9A is a simplified schematic illustrating a possible configuration of the présentinvention in a vertical production well. In FIG. 9A, there are five downhole tracer injectiondevices (Tj-T5) 60 located at various places along the depth of the vertical well at theproduction zone 48 for injecting tracer materials within the flow stream at various depths. Adownhole sensor device 140 is located upstream of the tracer injection devices (T1-T5) 60 fordetecting tracer materials in the flow stream as they pass. The sensor device 140 may 13129 ‘ 27 comprise multiple sensors 108, each being adapted to detect a different tracer materialsignature corresponding to the different tracer injection devices (T1-T5) 60. Altematively thesame tracer may be used in ail injector devices and the origin of the tracer puise determined byselecting the injector device individually. Thus, a tracer material expelled from the middletracer injection device (T3) 60 and detected at the sensor device 140 provides informationabout the flow stream entering the production tubing 40 at the middle tracer injectiondevice (T3) 60. The downhole sensor device 140 may also be located at the surface. But itmay be more désirable in some cases to hâve the downhole sensor device 140 located doser tothe tracer injection point so that the tracer material is less diluted by fluids in the flow stream. FIG. 9B is a simplified schematic illustrating another possible configuration of theprésent invention in a vertical production well. In FIG. 9B, there are five downhole tracerinjection devices (T1-T5) 60 located at various places along the depth of the vertical well at theproduction zone 48 for injecting tracer materials within the flow stream at various depths. Butinstead of having one sensor device 140 as shown in FIG. 9A, in FIG. 9B there are fiveseparate, downhole sensor devices (S 1-S5) 140 at various places along the depth of the verticalwell. Each sensor device (S1-S5) corresponds to a tracer injection device (T1-T5) 60,respectively. Hence, sensor device S4 comprises a sensor 108 adapted to detect a tracermaterial expelled from tracer injection device T4. In such a configuration, a sensor device 140at the same location as a tracer injection device 60 (e.g., sensor device S2 and tracer injectiondevice T3) may be electrically connected to each other, may be electrically connected across asame induction choke, may operate from a same communications and control module, mayshare a same modem, and/or may be comprised within a same housing. FIG. 9C is a simplified schematic illustrating a possible configuration of the présentinvention in a vertical injection well. In FIG. 9C, there are six sensor devices (Si-Sô) 140adapted to detect a tracer material injected into the well at the surface by a tracer injectiondevice 60. For injection wells, it will typically only be necessary to inject the tracer materialsat the surface because most or ail of the flow stream is originating from the surface. However,it is still possible to hâve one or more tracer injection devices 60 at various locations downholein addition to or instead of the tracer injection device 60 at the surface.

The configurations of FIGs. 9A-9C can be combined so that the placement of tracerinjection devices 60 and sensor devices 140 provides tracer détection and controllable tracerinjection for use during both production and injection stages of producing petroleum for a well. 13129- 28

Hence, the well can be switch from a producing stage to an injecting stage (and vice versa)without the need to reconfigure tracer injection devices 160 and sensor devices 40 downhole inthe well. Therefore, the tracer injection devices 60 and sensor devices 140 can be permanentlyinstalled for long terni use and for multiple uses. FIG. 9D is a simplified schematic illustrating a possible configuration of the présentinvention in a production well having a horizontal completion. In FIG. 9D, there are sevendownhole tracer injection devices (T1-T7) 60 located at various places along the horizontalsection at the production zone 48 for injecting tracer materials within the flow stream atvarious locations. As in FIG. 9A, a downhole sensor device 140 is located upstream of thetracer injection devices (T1-T7) 60 for detecting tracer materials in the flow stream as they pass. FIG. 9E is a simplified schematic illustrating another possible configuration of theprésent invention in a production well having a horizontal completion. The configuration inFIG. 9E is the same as the configuration in FIG. 9B, except that a sensor or sensors 108 fordetecting the tracer materials is located at the surface. The sensor 108 may be a stand alonesensor device 140, or it may be part of a surface computer System 64. FIG. 9F is a simplified schematic illustrating yet another possible configuration of theprésent invention in a production well having a horizontal completion. The configuration inFIG. 9F is similar to the configuration in FIG. 9B in that there are multiple sensor devices (Si-S7) 140 corresponding to the multiple tracer injection devices (T1-T7) 60. FIG. 9G is a simplified schematic illustrating a possible configuration of the présentinvention in an injection well having a horizontal section. The configuration in FIG. 9G issimilar to the configuration in FIG. 9C in that there are multiple downhole sensor devices (Si-S7) 140 adapted to detect tracer material injected into the well at the surface by a tracerinjection device 60. In alternative, the tracer injection device 60 may be located downhole. FIG. 9H is a simplified schematic illustrating a possible configuration of the présentinvention in a production well having multiple latéral complétions. In FIG. 9H, there are tracerinjection devices (T1-T4) 60 within the latéral branches, with each tracer injection device 60being near the junction between a latéral branch and the main borehole. Such placement of thetracer injection devices (T1-T4) 60 has the advantage of ease in installation (relative toinstalling a device farther downhole within a latéral branch). A sensor device 140 is located 29 13129 · upstream of the uppermost latéral branch. The sensor device 140 is adapted to detect tracermaterials injected into the latéral branches by the tracer injection devices (T1-T4) 60. Hence,the sensor device 140 may comprise multiple sensors 108 adapted to detect multiple tracermaterial signatures. In alternative, the sensor device 140 Or sensors 108 may be located at thesurface, but the downhole location shown in FIG. 9H is sometimes more preferred. FIG. 91 is a simplified schematic illustrating another possible configuration of theprésent invention in a production well having multiple latéral complétions. In FIG. 91, as inFIG. 9H, there are tracer injection devices (T1-T4) 60 shortly within the latéral branches. Butin FIG. 91, there are four sensor devices (S1-S4) 140, one for each tracer injection device (Ti-T4) 60, respectively. Hence, sensor device S3 is adapted to detect a tracer material injected intothe flow stream by tracer injection device T3, which provides flow information regarding thelatéral branch having tracer injection device T3 therein. Because sensor devices S3 and S4 arelocated at the same location, they may be combined into a single sensor device 140 havingmultiple sensors 108. FIG. 9J is a simplified schematic illustrating yet another possible configuration of theprésent invention in a production well having a multiple latéral complétions. In FIG. 9J, tracerinjection devices (T2-T4) 60 are located within the latéral branches near the production zones48, and a tracer injection device (T}) 60 is located within the vertical portion below the latéralbranches. Sensor devices (S2-S4) 140 are located upstream of the tracer injection devices (T2-T4) 60, respectively, within the laterals near the vertical section. A sensor device (Si) islocated up stream of tracer device (Ti) and below the latéral branches. Hence, the flow streamin each section of the well can be independently monitored.

For the configurations illustrated in FIGs. 9A-9J where there are multiple tracerinjection devices 60 and/or multiple sensor devices 140, the tracer injection devices 60 and/orthe sensor devices 140 may be located at equally spaced intervals. However, the multipletracer injection devices 60 and/or the sensor devices 140 may also be randomly spaced fromeach other or at any other spacing arrangement. Furthermore, each of the multiple tracerinjection devices 60 and/or the sensor devices 140 may hâve its own induction choke toprovide power and/or communications, or some or ail of the tracer injection devices 60 and/orthe sensor devices 140 may share an induction choke. Because the tracer injection devices 60and the sensor devices 140 can be independently addressable and independently controlled,one or more well sections can be independently monitored. 13129‘ 30

Below are numerous calculations to illustrate how information or measurementsobtained while using the présent invention can be used to détermine fluid movement or flowcharacteristics of a well during production or injection. The calculations provided below areposed for inflow of fluids into a production well. However with slight modification, they alsocan be applied to injection well profiles in which tracer is injected at one location at the top ofthe interval, and arrivai time is observed at spaced monitors along the open interval. Définitions: Δχί = thickness of layer i [ft] h = total thickness of interval [ ft ] ij = inflow rate into well per unit length from layer i [ barrels / day /ft ]q, = ij Axj - flow rate into well from layer i [ barrels / day ]qT = Lqi = total flow rate into well [ barrels / day ]

Qi = flow rate inside well at depthof layer i [ barrels / day ] QT = total flow rate out of well = qi [ barrels / day ] n = interval number (counted from top down) N = total number of intervals vp = volume of injected tracer puise [cc] cp = concentration of tracer in injected puise [gm/cc ] vp cp = mass of tracer injected [gm ] r = radius of well [ ft ] tj = transit time across layer i

Assumptions: (1) Δχί = ΔΧ2 = ΔΧ3 = ... Δχη (2) ii Δχί + Î2 ΔΧ2 + Ι3 Δχ3 ... +ίη Δχ„ = qT (no crossflow) CASE I Uniform Inflow ii = constant [ bbls / day / ft ] (3)

The flow rate in the well at layer i is the sum of the inflow rates in ail of the layers below, andin, layer i: 13129· 31

Qi - qN + qN-i + · · · + qi (4)

The transit time across layer i is: t, = (π r2 ΔχΟ / (Qi) = (π ΓΔχ;) / ( Σν ii Δχι ) = (π r2) / ( Σν ii ) (5)

The total transit time from inflow from layer k to the top of the interval is: ÎTk = ti + t2 + t3 (6) tîk = Σ? h (7)

An example calculation for four layers with a constant rate of inflow is given below.Beginning at the bottom of the interval, the flow rate inside the well increases as each layersuccessively feeds into the well (see Table 1, Column 2). For this case in which layerthicknesses are equal, the well volume opposite each layer is equal. Therefore the transit timeof fluids in the well across that layer is inversely proportional to the flow rate in the well (seeTable 1, Column 3). Now summing these layer transit times from the top down to a layer inwhich a tracer has been injected in the well stream, gives the total transit time for a tracer toarrive at the top of the producing interval (see Table 1, Column 4). Injected tracer is diluted byinflow fluids that enter above the tracer injection point. Thus, the concentration of tracer thatarrives at the top of the interval relative to the initial injected concentration may be calculatedby dividing the flow rate in the well at the injection point by the flow rate at the top of theinterval, that is, by the total flow rate (see Table 1, Column 5). TABLE1

Layer Flow Rate in Well Layer Transit Time L = πτ2/Σ( Total Transit Time tîk = t, + t2 + t3+t4 Arrivai Concen- tration 1 q, + q2 + q3 + q» πτ2/4( (π r2/()(1/4) 4/4 2 qi + qz + qj π r2 / 3 ( (π r2/()(1/4+1/3) 3/4 13129 32 3 qi + <k π r2 / 2 ij (π r2 / L) (1/4+173+1/2) 2/4 4 qi π r2 /1 i; (π r2 / i;) (1/4+1/3+172+1/1) 1/4 FIG. 10 illustrâtes the relative arrivai times at the top of the interval for fluids enteringthe well at 100 locations along the interval. FIG. 11 illustrâtes the relative arrivai times at the top of the interval for fluids enteringthe 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 a vertical well from a layeris a fonction of the permeability ratio (k), the thickness (Ay,) and the normalized inflow ratedetermined by the pressure gradient. q; = k; ii Ayi = flow rate into well from layer i [ barrels / day ] (8)

Where, i, = constant [ bbls / day / ft ]

Again, the flow rate in the well at layer i is the sum of the inflow rates in ail of the layersbelow, and in layer i:

Qi= qN+ qN-i + ··· + q> (9)

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

Ah = (π r2 Ayû / (Qj) = (π r2 AyO / Σν (Aij kj Ayj ) (10)

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

Atn = Ati + At2 + ... + Atj (11)

Atri = Zi'Atk

Wells with Multiple Latéral Horizontal Complétions (12) 13129 33

When wells are completed with multiple latéral horizontal branches, as shown in FIGs.9H-9J, the productivity of individual branches cannot be determined by conventional loggingor profile measurements. Information on the productivity of individual laterals would beusefiil in réservoir management that might lead to workovers or infill wells in the direction ofpoorly completed laterals. Similarly, if the production from a well, as observed at the surface,displays a sudden increase in water or gas, it is usefiil to détermine which latéral is causing theproblem. In the simplest application of the use of tracers for latéral well diagnosis, the tracerinjection point may be located a short distance into the latéral by any of the methods ofplacement discussed above (see FIGs. 9H and 91). The detector may be located in the verticalsection of the well above the uppermost latéral. Laterals having low productivity will displaylong, dilute tracer response, because the transit time in that latéral is long compared to that inthe vertical pipe.

Injection Wells with Long VerticalOpen Intervals

In formations being water flooded over long intervals, the maintenance of uniforminjection profiles is essential to assure effective flood-out of the whole oil bearing zone. In atypical injection well completiott, fluid is injected through tubing under a packer and allowedto enter the objective zone through perforations in the casing pipe or through a screened liner.In this application a number detectors may be installed along the casing or liner, or preferablyalong a perforated extension of the tubing below the packer (see FIG. 9C). With thisconfiguration, the tracer may be injected at the surface, and the arrivai time at the variousdetectors used to détermine the injectivity profile. With surface read-out of the detectors, acomplété history of the fluid injection profile throughout the flooded zone can be obtained. Inthe case of injection wells, particular care must be taken to iflix the injected tracer thoroughlyto avoid segregated flow near the wall of the pipe. The reason for this is that fluids are leavingthe well at the wall; hence tracer that stays near the wall will exit the well in the upper layersand not be available for measurements on the lower zones.

An example is given below to demonstrate how tracer arrivai times observed at widelyspaced monitors can be used to calculate the injection profile in a heterogeneous intervalcomposed of zones having widely variable permeabilities.

Example Water Injection Well: 34 13129 5 Diameter: d = ôinches.

Well Completion: 101’ of unperforated pipe below packer; 500’ of perforated interval;

Total Injection Rate: 800 barrels per day. 10 injectivity profile: SeeFIG. 1 2. TABLE 2

15 INJECTION PROFILE

Tracer Injection at packer, 101 feet above open interval;Tracer Monitoring Devices at 50’ spacing over open interval. ZONE DEPTH RATE Zonel 0-100ft. 100 barrels/day Zone II 100-200 fi. 400 barrels/day Zone III 200 - 300 ft. 0 barrels/day Zone IV 300 - 400 ft. 100 barrels/day Zone V 400 - 500 ft. 200 barrels/day

The time in minutes for the tracer to travel from one location to the next is: 20 t; = (π r2 )(Ayi) / (QO (13)

= [(n/4)(l/d)2 (1440)/5.615] (Ays) / (QO= [(201.42)(l/d)2 ] (AyO / (QO= [(201.42)(1/2)2 ](AyO / (QO

fi = (50.355 )(AyO/(QO (14) 13129 35

Therefore, the time for the tracer to travel from the injection point to the top of the openinterval is: to = (50.355)( Ay0)/(Q0) t0 = (50.355)( 101)/(800) = 6.357319 minutes

Thereafter, the rate in the well decreases as water leaves the perforated interval. Using veryshort intervals (Ay; = 1 ft), the inverse velocity or transit time (Atj) can be calculated for eachdepth: Δ!,· = (50.355)( ΔΥί) / (Qâvg) = (50.355 )(ΔΥί) / (Qi.j+QO/2 (15)

For the fïrst 100 feet, the injectivity is 1 b/d/ft, Δΐ, = (50.355)(1)/(800+799)/2 = 0.062983 minΔί2 = (50.355)(1)/(799+798)/2 = 0.063062 min Δίιοο = (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

At200 = (50.355)(1)/(304+300)/2 = 0.166738 min

For the third 100 feet, the injectivity is 0 b/d/ft, Δί2οι = (50.355)(1)/(300+300)/2 = 0.16785 min

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

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

Atjoi = (50.355)(1)/(300+299)/2 = 0.16813 min Δί4οο = (50.355)(1)/(201+200)/2 = 0.25114 min 13129 36

For the fifth 100 feet, the injectivity is 2 b/d/ft, ΔΪ40! = (50.355)(1) / (200+198)/2 = 0.25304 min Δΐ5Οο = (50.355)(1)/(2+0)/2 = 50.335 min FIG. 13 shows that these calculations closely approximate the actual flow rates that would beobserved in a well with the injection profile given above. FIG. 14 shows the cumulative sumof ail of the interval times: tn- t0 + Zi500 Atk (16) and we note that only subtle changes in arrivai times are seen in this display even thoughinjectivities vary from 0 to 4 b/d/ft.

The number of monitoring points is limited by practical considérations. If tracermonitoring modules are spaced at 50 foot intervals the arrivai times at these positions may beused to calculate injection rates as a function of depth as follows: Î50 = t0 + ΔΪ50 (17) = t0 +(50.355)( Ay5o)/(Q50+Qo)/2 (18)

Knowing the flow rate being injected into the well and the arrivai times of the tracer at the topof the open interval and at 50 feet down, we may calculate the rate in the well at that depth(Qso),

Qso = [(100.71)( Ay5o)/(t5o-to)] - Qo (19) = [(100.71)(50)/ (9.607156-6.357319)] - 800

= 749.4624 B/D

Using the calculated rate and the arrivai times of tracer at that depth, we may solve for the flowrate (Qioo) at the next monitor from the arrivai time at that depth (100 feet).

Qioo = [(100.71)(50)/ (13.08129-9.607156)] - 749.4624

= 699.9629 B/D 13129-

Successively, we calculate flow rates at each monitor down to the bottom of the interval. FIG. 15 compares the actual flow rates with the values calculated from the 50footreadings. Correspondence is good, with the exception of the bottom location where flow rategoes to zéro and transit times become infinité.

This method of calculating flow rates can be applied to longer spacing as well.However, when the fraction of total flow entering the formation in the interval between twomonitors is large compared to that passing the upper monitor, significant errors are introduced.For example, if 100 foot spacing is used in the calculation above, the predicted flow rate is toolow in Zone II where the true well flow rate decreases from 700 b/d to 300 b/d, as shown inFIG. 15. The reason for this déviation is the use of the interval average flow rate for matchingthe interval transit time.

If the transit time of the zone (Afr) is matched to a sériés of Ns transits of subzones eachof which reflects an equal loss of fluid into the formation, a corrected flow rate at the bottom ofthe zone (Qn) is obtained as follows:

Afr = (50.355)( Ay„) {[1/ Qo] +[1/ (1/NS) (Q0-Qn)]+ +[1/ (2/Ns) (Qo-Qn)] + [1/ (3/N) (Qo-Qn)] · · · + [1/ (NM) (Qo-Qn)] (20)

AtUQo)/ (50.355)( Ayn) = {[1] + [1/(1-(1/NS)+(1/NS) (QN/Qo))] + + [1/ (l-(2/Ns)+(2/Ns) (Qn/Q0))]+ + [1/ (l-(3/Ns)+(3/Ns) (Qn/Qo))]+ + [1/ (1-(NM)+(NM) (Qn/Qo))]} (21)

The transit time of the zone (Atf) is known from arrivai time observations at the top andbottom ofthe zone. The sub-zone thickness ( Ay„) is equal to the thickness ofthe zone dividedby the number of sub-zones selected (Ns). The well flow rate at the top of the zone (Qo) isobtained from the calculated value of flow rate at the base of the previous zone. The flow rateat the bottom of the présent zone (Qn) is obtained by itération since an explicit solution of Qnin Equation 21 is not available.

Production Wells with Long Vertical Open Intervals 13129 38

Inflow profiles of long interval vertical production wells can be analyzed by a methodsimilar to that described above. However, there are some différences that must be taken intoaccount. In an injection well, the tracer can be injected at a single point at the surface in theflow stream that is moving at the maximum velocity (see FIG. 9C). The tracer will pass alongthe well at a diminishing velocity. The only part of the well not amenable to tracer arrivai isthe very bottom section where flow rate becomes negligible. In the case of a production well,the tracer must be injected below the interval being analyzed (see FIGs. 9A and 9Bj. Near thebottom, flow rates will be small, and concentrations of tracer will be continuously diluted byinflow from the formation as the tracer moves uphole. In practical applications, the arrivaitimes of tracer injected near the bottom will be too long and its concentration will be too low toobtain useful information in the upper part of the formation. A less complété définition ofproductivity profile can be obtained by using pairs of tracer injection modules with détectionmodules.

Unlike injection wells where the tracer moves radially outward as the flow streammoves down the hole, production wells exhibit a radially inward movement as the producedfluids move up the hole. Unless mixing occurs, a tracer injected at the wall will eventuallyoccupy the very center of the well as it flows up the well. This means that there is no danger ofthe tracer exiting the well, but care must be taken at the détection point to avoid missing thepassage of the tracer when the detector is located at the wall. One possible solution is the useof turbulators in the well located immediately below the detectors to assure that tracer passes atthe wall.

The analyses above présumé a dominant phase flowing in the well that can be observedby a single tracer. In practice, most production wells hâve combinations of oil, water, and gasflowing in the well. Under these conditions, the buoyant forces may resuit in a rapid transportof phases compared to the average fluid velocity. A wide variety of downhole conditions existin commercial oil and gas wells, and many opportunities are available for the use of downholedetectors for spécifie production conditions. These conditions should be évident to thoseskilled in production well practice.

An example of useful information that might be obtained by such devices is thelocation of entry points for water or gas. In water flooding, there is often a différence insalinity of the original formation water and the injected flood water. The arrivai of fresh waterat the surface at individual wells of a water flood has been used for many years to monitor 39 13129 5 breakthrough. However, in long interval wells there is no simple way to learn the spécifie zonein the vertical section that is breaking through. Permanently mounted detectors located alongthe open interval can be used to monitor the progress of a flood and provide guidance forremédiai work to exclude the water breakthrough.

An example calculation is given below to demonstrate how arrivai times of produced 10 fluids at the top of an interval can be used to infer productivity profiles as a function of depth.Equations 3-12 given above are used inthis calculation.

Example Vertical Production Well: TABLE 3

DIMENSIONLESS PRODUCTIVITY PROFILES

PROFILE DEPTH [ 1 ] RATE [ l3/t /1] Uniform 0-100 IX Chart A 0-50 2X 50 -100 0 Chart B 0-50 0 50-100 2X ChartC 0-10 5X 10-90 0 90-100 5X 15 FIG. 16 shows cumulative inflow of fluids as a function of depth for these four profiles.FIG. 17 compares arrivai times for cases of Charts A-C as defined in TABLE 3 and FIG. 16.Compared to a uniform inflow profile, large différences in arrivai times are observed whenflow is non-uniform. In each of these profiles the total dimensionless flow rate is 1.0. For 20 uniform inflow, the rate per unit depth is IX. When ail of the flow is in the upper half, at a rateof 2X (Chart A), no transport of fluid occurs in the lower half and arrivai finie becomes infinitéfor fluid entering at the midpoint of the interval. When ail of the flow is in the lower half at arate of 2X (Chart B), arrivai times are short throughout the interval. When flow rate occurs 40 13129 only in the in the bottom and top 10% of the interval at 5X (Chart C), the transit times of fluidsfrom the bottom are faster than for the uniform case and then become slower than the uniformcase for fluids entering near the top. FIG. 18 shows that the shapes of the relative arrivai times are distinctive for variousprofiles, and thus the productivity profiles may be estimated by using a sériés of tracerinjection points spaced along the interval (see FIGs. 9A and 9B).

In addition to the arrivai times, the concentration of a slug of tracer which arrives at thetop of the interval from locations along the open interval can be used to verify interprétation ofa productivity profile. Dilution of a tracer slug by ail of the inflow of fluids above the tracerinjection point is assumed, such as is calculated in column 5 of Table 1. FIGS. 19, 20, 21, and 22 show the tracer concentrations and arrivai times at the top ofthe formation for four profiles.

Production Wells with Long Horizontal Open Intervals

Unlike vertical wells with long complétions, wells with long horizontal complétions areusually completed in a single géologie layer, and hence their productivity profiles are lessdépendent on différences in layer permeabilities. In these wells the maintenance of uniformprofiles is equally important. However, the pressure gradient along the open interval tends toresuit in higher production rates at the heel than at the toe of the well because greater pressuredrawdown can be achieved near the vertical section (the heel). High production rates inportions of the open interval can lead to early gas coning from above the oil producingélévation, or water coning from below it. Tracer monitoring, with spaced devices in thehorizontal portion (see FIGs. 9D-9G), would be useful in providing information for propercontrol of the inflow in these wells.

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

Example Horizontal Well Analysis: 13129 41

L

N

AL n

Qn

Pn

Ph dqf

Aqf

Aq„

Apn = length of entire open interval [ ft ] = numberof monitor points (subsections) -L/N = spacing of monitors [ft] = index of subsection ( from toe to heel ) = total flow rate from well [ b/d ] = total pressure drop over open interval [ psi ] = head loss from flow in well [( psi/ft) / (b/d) ] = spécifie inflow rate with uniform profile from formation intowell [b/d / ft] = inflow rate from formation into a subsection of the well [ b/d ]= flow rate in the well at subsection (n) [ b/d ] = pressure drop in subsection n =pH(AL)(Aq„) [psi]

Assuming the well is subdivided into N well sections, from upstream (toe to heel),n = 1,2,3,4,...N (22)

With uniform inflow,

Aqf = AL(Qn/L) [1,1, 1,1,...1] (23)

The flow rate in the well cumulâtes as inflow occurs from the toe to the heel,

Aqn = AL(QN/L)[l,2,3,4, ...N] (24)

The pressure drop in each subsection is assumed proportional to the flow rate,therefore,

Apn = AL (Aq„ )(pH) [ 1, 2, 3, 4,... N ] (25)

Adding the pressure drops in each subsection, the total pressure drop in the well fromthe toe to the successively downstream subsections is

Pn = Σΐ" Apn (26)

Pn = Σιη AL (Aqn )(pH) (n)(n+l)/2) (27) pn = AL(Aqn)(pH)[l,3,6,10, 15,... N(N+l)/2 ] (28)

Assumptions: length of entire open interval = 2500 ft spacing of monitors = 100 ft 42 13129. total flow rate from well = 2500 b/dspécifie head loss in well = 10"4 psi / b/d / ft

Inflow at Toe of Well, No Inflow along Interval (1) For a well in which ail 2500 barrels are flowing through 2500 feet of the well thepressure drop would be: (Qn)( L )( ph ) = (2500)(2500)(10-4) = 625 psi (29)

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 is: (Aq„)( AL )( p» ) [N(N+l)/2] = (100)(100)(10-4) (25)(26)/2 = 325 psi. (30)

Inflow Dépendent upon Réservoir Pressure

The inflow rate into the well is proportional to the différence between the réservoirpressure and the pressure in the well. Because the pressures in the well along the open intervaldépend on flow rate, the inflow profile must be obtained by an itérative calculation. We definethe réservoir pressure (pres) as some pressure (p0) above the highest pressure in the well, that is,the pressure at the toe.

Près Po + Ptoe (31)

The pressure différence between the réservoir pressure and the pressure in the well atlocations downstream from the toe is: Δρ; — (p0 + ptoe) “ (ptoe " Pn) — Po + Pn (32) Δρί = po + Σ AL (Aq„ Xph) ((n )(n+l)/2) (33) 1

In the first itération, the cumulative flow and cumulative pressure drop along the tubing may be calculated by summing the inflow differential pressures (p0 + pn) and normalizing the subsection differential pressures with that sum: 13129 43

Sum Δρί =ΣιΝ Δρ,· (34) Δρί

Normalized Δρί = Ρί = __ (35)

Sum Δρ, = ΣιΝ Δρί

The inflow rate of each subsection is proportional to this normalized differentialpressure, therefore, the inflow rate of each subsection is:

Qi = Pî(Qn)/(AL) (36)

The cumulative flow occurring in the weîl is:

Qi = Lqi(AL), (37) and the cumulative pressure drop in the well from the toe to the heel is: pni = ΣΣφ(ΔΣ)(ρη) (38) A second itération is made by substituting these values for the pressure drops intoEquation 31. Convergence is rapid—in this case only a few itérations are needed. These canbe carried out by substituting successive values of pni,2,3... in Equation 34. FIG. 23 présents the results of these pressure drop calculations for several inflowconditions. When ail of the flow enters the well at the toe, (Case 1—Open End Tubing), thecumulative pressure drop along the tubing is large since each section of the pipe expériencesthe maximum pressure drop. When flow is uniform along the length of the horizontal wellsection, (Case 2—Uniform Inflow), smaller pressure drops occur near the toe where flow ratesin the well are low. For the same total flow rate of 2500 b/d, the uniform inflow case results inonly about half the total pressure drop (325 psi) compared to Case 1, where the total pressuredrop is 625 psi. When inflow is dépendent on the réservoir pressure (Case 3—Non-UniformInflow), even lower pressure drops occur. If the réservoir pressure only slightly exceeds thewell toe pressure, and the pressure drop in the well is large by comparison, then most of theinflow occurs near the heel. The lower limit occurs when the réservoir pressure equals the welltoe pressure (i.e., p0 = 0) In that case the total pressure drop is 125 psi. The upper limit, whenréservoir pressure becomes large (p0 = 5»), results in uniform inflow. 13129· 44 5 FIG. 24 shows the calculated flow rates that resuit from various réservoir inflow conditions. The flow rates that occur along the horizontal well section under the conditionsgiven above may be normalized with respect to the flow rates in a well with uniform inflow.

Therefore, using the présent invention and the calculations provided herein, the flowstreams in a production or injection well can be monitored and characterized in real time as 10 needed. Information provided through the use of the présent invention can provide moreknowledge of the events occurring downhole and can be used to guide operators or a computerSystem in altering the production or injection procedures to optimize operations. Such uses cangreatly increase eflïciencies and maximize petroleum production from a given formation. Theprésent invention also may be applied to other types of wells (other than petroleum wells), such 15 as a water production well.

It will be appreciated by those skilled in the art having the benefit of this disclosure thatthis invention provides a petroleum production well having at least one electrically controllabletracer injection device, as well as methods of utilizing such devices to monitor the wellproduction. It should be understood that the drawings and detailed description herein are to be 20 regarded in an illustrative rather than a restrictive manner, and are not intended to limit theinvention to the particular forms and examples disclosed. On the contrary, the inventionincludes any further modifications, changes, rearrangements, substitutions, alternatives, designchoices, and embodiments apparent to those of ordinary skill in the art, without departing fromthe spirit and scope of this invention, as defined by the following daims. Thus, it is intended 25 that the following daims be interpreted to embrace ail such further modifications, changes,rearrangements, substitutions, alternatives, design choices, and embodiments.

Claims

13129 45 THE INVENTION CLAIMEDIS:

1. A tracer injection System for use in a well, comprising: a current impédance device being generally configured for positioning about a portionof a piping structure of said well and for impeding a time-varying electrical signal conveyedalong said portion of said piping structure; and a downhole, electrically controllable, tracer injection device adapted to be electricallyconnected to said piping structure adapted to be powered by said time varying electrical signal,and adapted to expel a tracer material into said well.

2. A tracer injection System in accordance with claim 1, wherein said current impédancedevice has a generally ring-shaped geometry and comprises a ferromagnetic material.

3. A tracer injection System in accordance with claim 1, wherein said piping structurecomprises at least a portion of a production tubing of said well, and said electrical retumcomprises at least a portion of a well casing of said well.

4. A tracer injection system in accordance with claim 1, wherein said piping structurecomprises at least a portion of a well casing.

5. A tracer injection System in accordance with claim 1, wherein said injection devicecomprises an electric motor and a communications and control module, said electrical motorbeing electrically connected to and adapted to be controlled by said communications and control module.

6. A tracer injection System in accordance with claim 1, wherein said injection devicecomprises an electrically controllable valve and a communications and control module, said 13129 46 electrically controllable valve being electrically connected to and adapted to be controlled by said communications and control module.

7. A tracer injection System in accordance with claim 1, wherein said injection devicecomprises a tracer material réservoir and a tracer injector, said tracer material réservoir beingin fluid communication with said tracer injector, and said tracer injector being adapted to expelfrom said injection device said tracer material from within said tracer material réservoir inresponse to an electrical signal.

8. A tracer injection System in accordance with claim 1, wherein said electricàl signal is apower signal.

9. A tracer injection System in accordance with claim 1, wherein said electrical signal is acommunication signal for controlling the operation of said tracer injection device.

10. A tracer injection System in accordance with claim 1, iùrther comprising a sensoradapted to detect said tracer material as said tracer material passes said sensor in a flow stream.

11. A tracer injection System in accordance with claim 1, further comprising a nozzleextension tube extending from said tracer injection device.

12. A petroleum well for producing petroleum products, comprising:a piping structure disposed within the borehole of the well; a current impédance device located about said piping structure to define an electricallyconductive portion of said piping structure; a source of time-varying signal electrically connected to said electrically conductiveportion of said piping structure; and 13129· 47 an electrically controllable tracer injection device electrically connected to saidconductive portion and adapted for coupling to said time-varying signal.

13. A petroleum well in accordance with claim 12, wherein said current impédance devicecomprises an upowered induction choke comprising a ferromagnetic material, such that saidinduction choke fonctions based on its size, geometry, spatial relationship to said pipingstructure, and magnetic properties.

14. A petroleum well in accordance with claim 12, wherein said piping structure comprisesa production tubing and well casing, said time varying signal being applied to at least one ofsaid tubing and casing.

15. A petroleum well in accordance with claim 12, wherein said tracer injection devicecomprises an electrically controllable valve.

16. A petroleum well in accordance with claim 12, wherein said tracer injection devicecomprises an electric motor.

17. A petroleum well in accordance with claim 12, wherein said tracer injection devicecomprises a modem.

18. A petroleum well in accordance with claim 12, wherein said tracer injection devicecomprises a tracer material réservoir.

19. A petroleum well in accordance with claim 12, forther comprising a sensor adapted to detect a tracer material. 13129· 48 5 20. A petroleum well in accordance with claim 12, further comprising a nozzle extension tube extending ftom said tracer injection device.

21. A petroleum well for producing petroleum products comprising:a well casing extending within a wellbore of said well; a production tubing extending within said casing; 10 a source of time-varying electrical current located at the surface, said current source being electrically connected to, and adapted to output a time-varying current into, at least oneof said tubing and said casing; a downhole tracer injection device comprising a communications and control module, atracer material réservoir, and an electrically controllable tracer injector, said communications 15 and control module being electrically connected to at least one of said tubing and said casing,said tracer injector being electrically connected to said communications and control module,and said tracer material réservoir being in fluid communication with said tracer injector; a downhole current impédance device being located about a portion of at least one ofsaid tubing and said casing, and said current impédance device being adapted to route part of 20 said electrical current through said communications and control module.

22. A petroleum well in accordance with claim 21, including a sensor device electricallyconnected to at least one of said tubing and said casing, said sensor device comprising a sensoradapted to detect a tracer material in a flow stream of said well.

23. A petroleum well in accordance with claim 21, further comprising a nozzle extension25 tube extending from said tracer injector. 13129. 49

24. A petroleum well in accordance with claim 21, wherein sàid tracer injector comprisesan electric motor, a screw mechanism, and a nozzle, said electric motor being electricallyconnected to said communications and control module, said screw mechanism beingmechanically coupled to said electric motor, said nozzle extending into an interior of saidtubing, said nozzle providing a fluid passageway between said tracer material réservoir andsaid tubing interior, and said screw mechanism being adapted to drive tracer material out ofsaid tracer material réservoir and into said tubing interior via said nozzle in response to a rotational motion of said electric motor.

25. A petroleum well in accordance with claim 21, wherein said tracer material réservoircomprises a separator therein that divides an interior of said tracer material réservoir into twovolumes, and wherein said tracer injector comprises an electrically controllable valve and anozzle, a first of said réservoir interior volumes containing a tracer material, a second of saidréservoir interior volumes containing a pressurized gas such that said gas exerts pressure onsaid tracer material in said first volume, said electrically controllable valve being electricallyconnected to and controlled by said communications and control module, and said firstvolume being fluidly connected to an interior of said tubing via said electrically controllable valve and via said nozzle.

26. A petroleum well in accordance with claim 21, wherein said tracer material réservoircomprises a separator therein that divides an interior of said tracer material réservoir into twovolumes, and wherein said tracer injector comprises an electrically controllable valve and anozzle, a first of said réservoir interior volumes containing a tracer material, a second of saidréservoir interior volumes containing a spring member such that said spring member exertspressure on said tracer material in said first volume, said electrically controllable valve beingelectrically connected to and controlled by said communications and control module, and said 13129 · 50 fïrst volume being fluidly connected to an interior of said tubing via said electrically controllable valve and via said nozzle.

27. A petroleum well in accordance with claim 21, wherein said current impédancedevice comprises an unpowered induction choke comprising a ferromagnetic material.

28. A petroleum well in accordance with claim 21, wherein said downhole injectiondevice further comprises a sensor, said sensor being electrically connected to saidcommunications and control module and said sensor being adapted to detect a tracer material.

29. A petroleum well in accordance with claim 21, wherein said communications andcontrol module comprises a modem.

30. A method of operating a petroleum well, comprising the steps of:providing a piping structure extending within a wellbore of said well;applying a time-varying electrical current to said piping structure; powering a downhole tracer injection system for said well using said time-varyingelectrical current applied to said piping structure; and injecting tracer material from said tracer injection System into a downhole flow stream within said well.

31. A method in accordance with claim 30, further comprising the steps of:monitoring said flow stream at a location remote from said tracer injection device; and detecting said tracer material within said flow stream.

32. A method in accordance with claim 30, further comprising the step of: 51 13129. 5 transmitting data corresponding to said detecting steps to a surface computer System via said piping structure.

33. A method in accordance with claim 30, fiirther comprising the step of: 10 locating a réservoir of tracer material in the main borehole of the well; injecting the tracer material into a latéral branch extending from the main borehole viaa capillary extending into the latéral.