OA12224A - Wireless downhole well interval inflow and injection control. - Google Patents

Abstract

Apparatus and methods of electrically controlling downhole well interval inflow and/or injection. The downhole controllable well section (71) comprises a communications and controle module (80), a sensor (82), an electrically controllable valve (84), and an induction choke (90). The electrically controllable valve (84) is adpated to regulate flow between an exterior of the tubing (40) and an interior (104) of the tubing. Power and signal transmission between surface and downhole is carried out via the tubing (40) and/or the casing (30). When there are multiple downhole controllable well sections (72-75), flow inhibitors (61-65) separate the well sections.

Description

1 01 2224

5 CROSS-REFERENCES ΤΟ RELATED APPLICATIONS

This application daims the benefit of the following U.S. Provisional Applications, ailof which are hereby incorporated by reference: COMMONLY OWNED AND PREVIOUSLY FILED U.S. PROVISIONAL PATENT APPLICATIONS T&K# Serial Number Title Filing 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 TH 1603 60/177,883 Permanent, Downhole, Wireless, Two-Way Telemetry Backbone Using Redundant Repeater, Spread Spectrum Arrays Jan. 24, 2000 TH 1668 t - 60/177,998 Petroleum Well Having Downhole Sensors, Communication, and Power Jan. 24, 2000 1 1 TH 1669 L........ 60/177,997 System and Method for Fluid Flow Optimization Jan. 24, 2000 j TS6185 60/181,322 A Method and Apparatus for the Optimal Predistortion of an Electromagnetic Signal in a Downiiole Communications System Feb. 9, 2000 , TH Î599x 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 front 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 Electricaî 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 Cas 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 front Distributed Batteries or Capacitors with Reconfigurable Discharge Mar. 2, 2000 2 012224 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 followingcommonly owned and concurrently filed applications, ail of which are hereby incorporatedby reference: 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 1671US 09/ Tracer Injection in a Production Well 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-Lift Well TH 1675US 09/ Wireless Smart Well Casing TH 1677US 09/ Method for Downhole Power Management Using Energization from Distributed Batteries or Capacitors with Reconfigurable Discharge 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 10 3 012224 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 TH 1600US 09/ Induction Choke for Power Distribution in Piping Structure TH 1602US 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 TS6185US 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 owned10 applications. The applications referenced in the tables above are referred to herein as the “Related Applications.” 4 012224 BACKGROUND OF THE INVENTION *

FIELD OF THE INVENTION

The présent invention relates to a petroleum well for producing petroleum products.

In one aspect, the présent invention relates to Systems and methods of electrically controllingdownhole well interval inflow and/or injection for producing petroleum products.

DESCRIPTION OF THE RELATED ART

Attainment of high recovery efficiency from thick hydrocarbon réservoirs, requiresuniform productivity from wells completed over long intervals.

In vertical wells, the open intervals typically include a number of géologie layershaving a variety of petrophysical properties and initial réservoir conditions. Variations inpermeability and initial réservoir pressure especially, resuit in uneven déplétion of layers, ifthe layers are produced as a unit with a single draw-down pressure. As the field is produced,high permeability layers are depleted faster than tight layers, and high pressure layers mayeven cross-flow into lower pressure layers.

In horizontal wells, the open completion interval is usually contained in a singlegéologie layer. However, uneven inflow can resuit from a pressure drop along the well. Thiseffect is particularly évident in long completion intervals where the réservoir pressure isnearly equal to the pressure in the well at the far end (the toe). In such a case, almost noinflow occurs at the toe. At the other end of the open interval near the vertical part of thewell (the heel), the greater différence between the réservoir pressure and the pressure in thewell results in higher inflow rates there. High inflow rates near the heel can lead to early gasbreakthrough from gas coning down, or early water breakthrough from water coning up. 5 012224

Productivity profiles of vertical wells are described by the steady State Darcy flowéquation for radial flow: _ 2?ckkrhkpqR H^(re/rw) (1) where qR =k =kr =àp = μ =re = rw = h = flow rate [ l31_1 ] absolute permeability [ l2 ] relative permeability [ unitless ] pressure draw-down = réservoir pressure-well pressure [ m Γ1t“2 ] viscosity [ m Γ1 t~l ] outer radius of réservoir [ 1 ] well radius [1] length of open interval [ 1 ]

Each flowing fluid may be described by this équation. In most wells, we need toaccount for flow of the gas, oil, and water. In the initial phase of production of a field,réservoir pressure is usually large. If large draw-down pressures are applied, inflow profileswill be uniform for layers with similar permeabilities because variations in initial réservoirpressure of layers are usually smaller than the draw-down pressure. As the well is producedand layers are depleted, the réservoir pressure affects the productivity profiles to a greaterextent because some layers may hâve a small draw-down, even if the well is produced at itslowest pressure. Variations in permeability among layers may anse ffom (1) différences ingrain sizç, sorting, and packing, or (2) ffom interférence of flowing fluids, i.e., the relativepermeability. The former—grain minerai framework—is not expected to change theproductivity profile very much during the life of the well because the grain frameworkremains unchanged, except for compaction. But compaction can equalize layerpermeabilities. The effects of fluid saturation on permeability lead to poor productivityprofiles because, for example, a high permeability layer is likely to hâve a high spécifie fluidsaturation, which makes that layer even more productive. During the life of a well thesesaturation effects can lead to even poorer profiles because, for example, gas or waterbreakthrough into a well results in increasing breakthrough fluid saturation and even higherproductivity of that fluid relative to the other layers.

Productivity profiles in horizontal wells may be affected by layering if the wellintersects dipping beds or if the horizontal well is slightly inclined and crosses an 6 012224 imperméable bed. However, the major effect is expected to be the différence in draw-downpressure between the toe and the heel.

The problems associated with poor productivity profiles in wells with long intervalcomplétions hâve been addressed in a recent patent application entitled “Minipumps in aDrainhole Section of a Well”, fîled 15 September 1999, inventors M.E. Amory, R. Daling, C.A. Glandt, R.N. Worrall, EPC Patent Application no. 99203017.1, herewith incorporatedby reference. This method proposes the use of several annular pumping devices locatedalong the open interval of the well to offset the pressure drop due to flow in the well andthereby increase the inflow at the toe of the well.

Wells may also be used for fluid injection. For example, water flooding is sometimesused to displace hydrocarbons in the formation towards producing wells. In water flooding, itis désirable to hâve uniform injection. Hence with fluid injection, the same issues arise withrespect to ensuring uniform injection as those mentioned above for seeking uniform inflow,and for the same reasons.

Conventional packers are known such as described in U.S. Patents 6,148,915, 6,123,148, 3,566,963 and 3,602,305.

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

BRIEF SUMMARY 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 petroleum well forproducing petroleum products, is provided. The petroleum well comprises a well casing, aproduction tubing, a source of time-varying current, and a downhole controllable wellsection. The well casing extends within a wellbore of the well, and the production tubingextends within the casing. The source of time-varying current is at the surface, andelectrically connected to the tubing and/or the casing, such that the tubing and/or the casingacts as an electrical conductor for transmitting time-varying electrical current from thesurface to a downhole location. The downhole controllable well section comprises acommunications and control module, a sensor, an electrically controllable valve, and aninduction choke. The communications and control module is electrically connected to the 7 012224 tubing and/or the casing. The sensor and the electrically controllable valve are electricallyconnected to the communications and control module. The electrically controllable valve isadapted to regulate flow between an exterior of the tubing and an interior of the tubing. Theinduction choke is located about a portion of the tubing and/or the casing. The inductionchoke is adapted to route part of the current through the communications and control moduleby creating a voltage potential within the tubing and/or the casing between one side of theinduction choke and another side of the induction choke. The communications and controlmodule is electrically connected across this voltage potential. The downhole controllablewell section may further comprise a flow inhibitor located within the casing and aboutanother portion of the tubing such that fluid flow within the casing from one side of the flowinhibitor to another side of the flow inhibitor is hindered by the flow inhibitor. In anembodiment with multiple well sections, a flow inhibitor may be used to defîne a boundarybetween the well sections. The sensor may be a fluid flow sensor, a fluid pressure sensor, afluid density sensor, or an acoustic waveform transducer.

In accordance with another aspect of the présent invention, a method of producingPetroleum from a petroleum well is provided. The method comprises the following steps, theorder of which may vary: (i) providing a plurality of downhole controllable well sections ofthe well for at least one petroleum production zone, each of the well sections comprising acommunications and control module, a flow sensor, an electrically controllable valve, and aflow inhibitor, the flow inhibitor being located within a well casing and about a portion of aproduction tubing of the well, the communications and control module being electricallyconnected to the tubing and/or the casing, and the electrically controllable valve and the flowsensor being electrically connected to the communications and control module; (ii) hinderingfluid flow between the well sections within the casing with the flow inhibitor; (iii) measuringfluid flow between the at least one petroleum production zone and an interior of the tubing ateach of the well sections with its respective flow sensor; (iv) regulating fluid flow betweenthe at least one petroleum production zone and the interior of the tubing at each of the wellsections with its respective electrically controllable valve, based on the fluid flowmeasurements; and (v) producing petroleum products from the well via the tubing.

The method may further comprise the following steps, the order of which may vary:(vi) inputting a time-varying current into the tubing and/or the casing from a current source atthe surface; (vii) impeding the current with an induction choke located about the tubingand/or the casing; (viii) creating a voltage potential between one side of the induction choke 8 01 2224 and another side of the induction choke within the tubing and/or the casing; (ix) routing thecurrent through at least one of the communications and control modules at the voltagepotential using the induction choke; and (x) powering at least one of the communications andcontrol modules using the voltage potential and the current from the tubing and/or the casing.Also, the method may further comprise the following steps, the order of which may vary: (xi) transmitting the fluid flow measurements to a computer System at the surface using thecommunications and control module via the tubing and/or the casing; (xii) calculating apressure drop along the well sections, with the computer System, and using the fluid flowmeasurements; (xiii) determining if adjustments are needed for the electrically controllablevalves of the well sections; (xiv) if valve adjustments are needed, sending command signaisto the communications and control modules of the well sections needing valve adjustment;and (xv) also if valve adjustments are needed, adjusting a position of the electricallycontrollable valve via the communications and control module for each of the well sectionsneeding valve adjustment.

In accordance with yet another aspect of the présent invention, a method ofcontrollably injecting fluid into a formation with a well is provided. The method comprisesthe following steps, the order of which may vary: (i) providing a plurality of controllablewell sections of the well for the formation, each of the well sections comprising acommunications and control module, a flow sensor, and an electrically controllable valve,and a flow inhibitor, the communications and control module being electrically connected tothe tubing and/or the casing, the electrically controllable valve and the flow sensor beingelectrically connected to the communications and control module, and the flow inhibitorbeing located within a well casing and about a portion of a tubing string of the well; (ii)hindering fluid flow between the well sections within the casing with the flow inhibitors; (iii)measuring fluid flow from an interior of the tubing into the formation at each of the wellsections with its respective flow sensor; (iv) regulating fluid flow from the tubing interior intothe formation at each of the well sections with its respective electrically controllable valve,based on the fluid flow measurements; and (v) controllably injecting fluid into the formationwith the well.

The method may further comprise the following steps, the order of which may vary:(vi) inputting a time-varying current into the tubing and/or the casing from a current source atthe surface; (vii) impeding the current with an induction choke located about the tubingand/or the casing; (viii) creating a voltage potential between one side of the induction choke 9 01 2224 and another side of the induction choke within the tubing and/or the casing; (ix) routing thecurrent through at least one of the communications and control modules at the voltagepotential using the induction choke; and (x) powering the at least one of the communicationsand control modules using the voltage potential and the current from the tubing and/or thecasing. Also, the method may further comprise the following steps, the order of which mayvary: (xi) transmitting the fluid flow measurements to a computer System at the surface usingthe communications and control module via the tubing and/or the casing; (xii) calculating apressure drop along the well sections, with the computer System, using the fluid flowmeasurements; (xiii) determining if adjustments are needed for the electrically controllablevalves of the well sections; (xiv) if valve adjustments are needed, sending command signaisto the communications and control modules of the well sections needing valve adjustment;and (xv) also if valve adjustments are needed, adjusting a position of the electricallycontrollable valve via the communications and control module for each of the well sectionsneeding valve adjustment.

The Related Applications describe ways to deliver electrical power to downholedevices, and to provide bi-directional communications between the surface and eachdownhole device individually. The downhole devices may contain sensors or transducers tomeasure downhole conditions, such as pressure, flow rate, liquid density, or acousticwaveforms. Such measurements can be transmitted to the surface and made available innear-real-time. The downhole devices may also comprise electrically controllable valves,pressure regulators, or other mechanical control devices that can be operated or whose set-points may be changed in real time by commands sent from the surface to each individualdevice downhole. Downhole devices to measure and control inflow or injection over longinterval complétions are placed within well sections. The measured flow rates are used tocontrol accompanying devices, which are used to regulate inflow from or injection intosubsections of the completion.

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. 1A is schematic of an upper portion of a petroleum well in accordance with a preferred embodiment of the présent invention; 10 012224 FIG. IB is schematic of an upper portion of a petroleum well in accordance withanother preferred embodiment of the présent invention; FIG. 2 is a schematic of a downhole portion of a petroleum production well inaccordance with a preferred embodiment of the présent invention; FIG. 3 is an enlarged view of a portion of FIG. 2 showing a well section of thepetroleum production well; FIG. 4 graphs cumulative pressure drop along production tubing as a fonction ofdistance along the tubing for a range of différences between réservoir pressure and well toepressure; and FIG. 5 graphs relative inflow rate as a fonction of distance along the tubing for arange of différences between the réservoir pressure and the pressure at the toe of the 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, a preferred embodiment of the présentinvention is illustrated and forther described, and other possible embodiments of the présentinvention are described. The figures are not necessarily drawn to scale, and in someinstances the drawings hâve been exaggerated and/or simplified in places for illustrativepurposes only. One of ordinary skill in the art will appreciate the many possible applicationsand variations of the présent invention based on the following examples of possibleembodiments of the présent invention, as well as based on those embodiments illustrated anddiscussed in the Related Applications, which are incorporated by reference herein to themaximum extent allowed by law.

As used in the présent application, a “piping structure” can be one single pipe, atubing string, 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 interconnectedpipes, or other similar structures known to one of ordinary skill in the art. A preferredembodiment makes use of the invention in the context of a petroleum well where the pipingstructure comprises tubular, metallic, electrically-conductive pipe or tubing strings, but theinvention is not so limited. For the présent invention, at least a portion of the piping structureneeds to be electrically conductive, such electrically conductive portion may be the entirepiping structure (e.g., Steel pipes, copper pipes) or a longitudinal extending electrically 11 012224 conductive portion combined with a longitudinally extending non-conductive portion. Inother words, an electrically conductive piping structure is one that provides an electricalconducting path from a first portion where a power source is electrically connected to asecond portion where a device and/or electrical retum is electrically connected. The pipingstructure will typically be conventional round métal tubing, but the cross-section geometry ofthe piping structure, or any portion thereof, can vary in shape (e.g., round, rectangular,square, oval) and size (e.g., length, diameter, wall thickness) along any portion of the pipingstructure. Hence, a piping structure must hâve an electrically conductive portion extendingfrom a first portion of the piping structure to a second portion of the piping structure, whereinthe first portion is distally spaced from the second portion along the piping structure.

Also note that the terni “modem” is used herein to generically refer to anycommunications device for transmitting and/or receiving electrical communication signaisvia an electrical conductor (e.g., métal). Hence, the term “modem” as used herein is notlimited to the acronym for a modulator (device that converts a voice or data signal into a formthat can be transmitted)/demodulator (a device that recovers an original signal after it hasmodulated a high frequency carrier). Also, the term “modem” as used herein is not limited toconventional computer modems that convert digital signais to analog signais and vice versa(e.g., to send digital data signais over the analog Public Switched Téléphoné Network). Forexample, if a sensor outputs measurements in an analog format, then such measurements mayonly need to be modulated (e.g., spread spectrum modulation) and transmitted--hence noanalog/digital conversion needed. As another example, a relay/slave modem orcommunication device may only need to identify, filter, amplify, and/or retransmit a signalreceived.

The term “valve” as used herein generally refers to any device that fonctions toregulate the flow of a fluid. Examples of valves include, but are not limited to, bellows-typegas-lift valves and controllable gas-lift valves, each of which may be used to regulate theflow of lift gas into a tubing string of a well. The internai and/or extemal workings of valvescan vary greatly, and in the présent application, it is not intended to limit the valves describedto any particular configuration, so long as the valve fonctions to regulate flow. Some of thevarious types of flow regulating mechanisms include, but are not limited to, bail valveconfigurations, needle valve configurations, gâte valve configurations, and cage valveconfigurations. The methods of installation for valves discussed in the présent applicationcan vary widely. 12 012224

The terni “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 from a surface computer or from 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.

The term “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 physicalquantity. A sensor as described herein can be used to measure physical quantities including,but not limited to: température, pressure (both absolute and differential), flow rate, seismicdata, acoustic data, pH level, salinity levels, valve positions, or almost any other physicaldata.

The phrase “at the surface” as used herein refers to a location that is above about fiftyfeet 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 is 13 012224 accessed vertically, horizontally, or any other angle therebetween. Also, the terni “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.”

Similarly, in accordance with conventional terminology of oilfield practice, thedescriptors “upper,” “lower,” “uphole,” and “downhole” are relative and refer to distancealong hole depth from the surface, which in deviated or horizontal wells may or may notaccord with vertical élévation measured with respect to a survey datum.

As used in the présent application, "wireless" means the absence of a conventional,insulated wire conductor e.g. extending from a downhole device to the surface. Using thetubing and/or casing as a conductor is considered "wireless."

Conventional horizontal wells are typiçally completed with perforated casings orscreened liners, some of which may be several thousand feet long and four to six inches indiameter. For wells that are prolific producers, the horizontal liner conducts ail of the flow toa vertical section. Production tubing and a packer may be placed within a vertical well casingof the vertical section, where gas lift or other artificial lift may be employed. However insuch conventional horizontal wells, the inflow rates of fluids from a production zone atvarious places along the extent of the horizontal well can vary greatly as the zone is depleted.Such variations can lead to an increased pressure drop along the horizontal well and theconséquent excessive inflow rate near the heel of the well relative to the toe, which istypiçally not désirable. The présent invention présents a solution to such problems, as well asothers, by providing a well with controllable well sections. FIG. 1A is schematic of an upper portion of a petroleum well 20 in accordance with apreferred embodiment of the présent invention. A well casing 30 and the tubing string 40 actas electrical conductors for the system. An insulating tubing joint 56 is incorporated at thewellhead to electrically insulate the tubing 40 from casing 30. Thus, the insulators 58 of thejoint 56 prevent an electrical short circuit between lower sections of the tubing 40 and casing30 at the hanger 34. A surface computer system 36 comprising a master modem 37 and asource of time-varying current 38 is electrically connected to the tubing string 40 below thehanger 34 by a first source terminal 39. The first source terminal 39 is insulated from thehanger 34 where it passes through it. A second source terminal 41 is electrically connected tothe well casing 30, either directly (as in FIG. 1 A) or via the hanger 34 (arrangement notshown). 14 012224

The time-varying current source 38 provides the time-varying electrical current,which carries power and communication signais downhole. The time-varying electricalcurrent is preferably altemating current (AC), but it can also be a varying direct current (DC).The communication signais can be generated by the master modem 37 and embedded wîthinthe current produced by the source 38. Preferably, the communication signal is a spreadspectrum signal, but other forms of modulation can be used in alternative.

As shown in FIG. IB, in alternative to or in addition to the insulated hanger 34, anupper induction choke 43 can be placed about the tubing 40 above the electrical connectionlocation for the first source terminal 39 to the tubing. The upper induction choke 43comprises a ferromagnetic material and is located generally concentrically about the tubing40. The upper induction choke 43 fonctions based on its size, geometry, spatial relationshipto the tubing 40, and magnetic properties. When time-varying current is imparted into thetubing 40 below the upper choke 43, the upper choke 43 acts as an inductor inhibiting theflow of the current between the tubing 40 below the upper choke 43 and the tubing 40 abovethe upper choke 43 due to the magnetic flux created within the upper choke 43 by the current.Thus, most of the current is routed down the tubing 40 (i.e., downhole), rather than shortingacross the hanger 45 to the casing 30. FIG. 2 is schematic of a downhole portion of a petroleum production well 20 inaccordance with a preferred embodiment of the présent invention. The well 20 has a verticalsection 22 and a horizontal section 24. The well has a well casing 30 extending within awellbore and through a formation 32, and a production tubing 40 extends within the wellcasing. Hence, the well 20 shown in FIG. 2 is similar to a conventional well in construction,but with the incorporation of the présent invention.

The vertical section 22 in fois embodiment incorporâtes a packer 44 which isfumished with an electrically insulating sleeve 76 such that the tubing 40 is electricallyinsulated from casing 30. The vertical section 22 is also fomished with a gas-lift valve 42 toprovide artificial lift for fluids within the tubing using gas bubbles 46. However, inalternative, other ways of providing artificial lift may be incorporated to form other possibleembodiments (e.g., rod pumping). Also, the vertical portion 22 can furfoer vary to formmany other possible embodiments. For example in an enhanced form, the vertical portion 22may incorporate one or more electrically controllable gas-lift valves, one or more inductionchokes, and/or one or more controllable packers comprising electrically controllable packervalves, as described in the Related Applications. 15 012224

The horizontal section 24 of the well 20 extends through a petroleum production zone48 (e.g., oil zone) of the formation 32. The location where the vertical section 22 and thehorizontal section 24 meet is referred to as the heel 50, and the distal end of the horizontalsection is referred to as the toe 52. At various locations along the horizontal section 24, thecasing 30 has perforated sections 54 that allow fluids to pass from the production zone 48into the casing 30. Numerous flow inhibitors 61-65 are placed along the horizontal section24 in the annular space 68 between the casing 30 and the tubing 40. The purpose of theseflow inhibitors 61-65 is to hinder or prevent fluid flow along the annulus 68 within the casing30, and to thus separate or form a sériés of controllable well sections 71-75. In theembodiment shown in FIG. 2, the flow inhibitors 61-65 are conventional packers withelectrically insulating sleeves to maintain electrical isolation between tubing 104 and casing54 (functionally équivalent to packer 44 with sleeve 76), which themselves are known in theart. However, any of the flow inhibitors 61-65 can be provided by any other way that makesthe cross-sectional area of the annular space 68 (between the casing 30 and the tubing 40)small compared to the internai cross-sectional area of the tubing 40, while maintainingelectrical isolation between tubing and casing. In other words, the flow inhibitors 61-65 donot necessarily need to form fluid-tight seals between the well sections 71-75, asconventional packers typically do. Thus, for example, any of the flow inhibitors 61-65 maybe (but is not limited to being): a conventional packer; a controllable packer comprising anelectrically controllable packer valve, as described in the Related Applications; a close-fittingtubular section; an enlarged portion of tubing; a collar about the tubing; or an inflatable collarabout the tubing. In an enhanced form, a controllable packer as a flow inhibitor can providevariable control over the fluid communication among well sections—such controllablepackers are further described in the Related Applications.

Referring to FIGs. 2 and 3, each controllable well section 71-75 comprises acommunications and control module 80, a sensor 82, and an electrically controllable valve84. In a preferred embodiment, each well section 71-75 further comprises a ferromagneticinduction choke 90. But in alternative embodiments, the number of downhole inductionchokes 90 may vary. For example, there may be one downhole induction choke 90 for two ormore well sections 71-75, and hence some of the well sections would not comprise aninduction choke.

Power for the electrical components of the well sections 71-75 is provided from the surface using the tubing 40 and casing 30 as electrical conductors. Hence, in a preferred 16 012224 embodiment, the tubing 40 acts as a piping structure and the casing 30 acts as an electricalretum to form an electrical circuit in the well 20. Also, the tubing 40 and casing 30 are usedas electrical conductors for communications signais between the surface (e.g., a surfacecomputer) and the downhole electrical devices within the controllable well sections 71-75.

In the embodiment shown in FIGs. 2 and 3, there is a downhole induction choke 90for each controllable well section 71-75. The downhole induction chokes 90 comprise aferromagnetic material and are unpowered. The downhole chokes 90 are located about thetubing 40, and each choke acts as a large inductor to AC in the well circuit formed by thetubing 40 and casing 30. The downhole chokes 90 function based on their size (mass),geometry, and magnetic properties, as described above regarding the upper choke. Thematerial composition of the chokes 43,90 may vary, as long as they exhibit the requisitemagnetic properties needed to act as an inductor to the time-varying current, which willdépend (in part) on the size of the current. FIG. 3 is an enlarged view of a controllable well section 71 ffom FIG. 2. Focusing onthe well section 71 of FIG. 3 as an example, the communications and control module 80 iselectrically connected to the tubing 40 for power and/or communications. A first deviceterminal 91 of the communications and control module 80 is electrically connected to thetubing 40 on a source-side 94 of the downhole induction choke 90. And, a second deviceterminal 92 of the communications and control module 80 is electrically connected to thetubing 40 on an electrical-retum-side 96 of the downhole induction choke 90. When AC isimparted into the tubing 40 at the surface, it travels ffeely downhole along the tubing until itencounters the downhole induction choke 90, which impedes the current flow through thetubing at the choke. This créâtes a voltage potential between the tubing 40 on the source-side94 of the downhole choke 90 and the tubing on the electrical-retum-side 96 of the choke.Because the communications and control module 80 is electrically connected across thevoltage potential formed by the downhole choke 90 when AC flows in the tubing 40, thedownhole induction choke 90 effectively routes most of the current through thecommunications and control module 80. The voltage potential also forms between thesource-side 94 of the tubing 40 and the casing 30 because the casing acts as an electricalretum for the well circuit. Thus in alternative, the communications and control module 80can be electrically connected across the voltage potential between the tubing 40 and thecasing 30. If in an enhanced form one or more of the flow inhibitors 61-65 is a packercomprising an electrically powered device (e.g., sensor, electrically controllable packer 17 012224 valve), the electrically powered device of the packer will likely also be electrically connectedacross the voltage potential createdby ,the downhole choke 90, either directly or via a nearbycommunications and control module 80.

Referring again to FIG. 2, the packer 65 at the toe 52 provides an electricalconnection between the tubing 40 and the casing 30, and the casing 30 is electricallyconnected to the surface computer System (not shown) to complété the electrical circuitformed by the well 20. Because in this embodiment it is not désirable to hâve the tubing 40electrically shorted to casing 30 between the surface and the toe 52, it is necessary toelectrically insulate part of the packers 44,61, 62, 63, 64 between the surface and the toe sothat they do not act as a shorts between the tubing 40 and the casing 30. Such electricalinsulation of a flow inhibitor may be achieved in various ways apparent to one of ordinaryskill in the art, including (but not limited to): an insulating sleeve about the tubing at the flowinhibitor location or about the flow inhibitor; an insulating coating on the tubing at the flowinhibitor location or on the radial extent of the flow inhibitor; a rubber or urethane portion atthe radial extent of packer slips; forming packer slips from non-electrically-conductivematerials; other known insulating means; or any combination thereof. In FIG. 3, theintermediate packers 44, 61,62,63,64 hâve an insulator at the radial extent of each packerwhere the packer contacts the casing 30 (e.g., the slips).

Other alternative ways to develop an electrical circuit using a piping structure of awell and at least one induction choke are described in the Related Applications, many ofwhich can be applied in conjunction with the présent invention to provide power and/orcommunications to the electrically powered downhole devices and to form otherembodiments of the présent invention.

Referring again to FIG. 3, preferably, a tubing pod 100 holds or contains thecommunications and control module 80, sensors 82, and electrically controllable valves 84together as one module for ease of handling and installation, as well as to protect thesecomponents from the surrounding environment. However, in other embodiments of theprésent invention, the components of the tubing pod 100 can be separate (i.e., no tubing pod)or combined in other combinations. Also, there may be multiple tubing pods per wellsection, which may be powered using one or more induction chokes for creating voltagepotential. Furthermore, multiple tubing pods may share a single communications and controlmodule. The various combinations possible are vast, but the core of a controllable wellsection is having at least one communications and control module, at least one sensor, and at 18 012224 least one electrically controllable valve therein. The contents of a communications andcontrol module may be as simple as a wire cormector terminal for distributing electricalconnections from the tubing 40, or it may be very complex comprising, for example (but notlimited to), a modem, a rechargeable battery, a power transformer, a microprocessor, amemory storage device, a data acquisition card, and a motion control card.

The tubing pod 100 shown in FIG. 3 has two sensors 82 and two electricallycontrollable valves 84. Each valve 84 has an electric motor 102 coupled thereto, via a set ofgears, for opening, closing, adjusting, or continuously throttling the valve position inresponse to command signais from the communications and control module 80. Theelectrically controllable valves 84 regulate fluid flow between an exterior (e.g., annulus 68,production zone 48) of the tubing 40 and an interior 104 of the tubing 40. In otherembodiments, the controlled-opening orifice of the tubing created by the valve 84 may becontrolled by the sensor 82, and may be actuàted by the natural hydraulic power in theflowing well, by stored electrical power, or other ways. The orifice of the valve 84 maycomprise a standard bail valve, a rotating sleeve, a linear sleeve valve, or any other devicesuitable to regulate flow. It may never be necessary to effect a complété shut-off or closingof the valve 84, but if needed, that type of valve may be used. Hence during petroleumproduction, fluids (e.g., oil) from the production zone 48 flow into the casing 30 via theperforated casing sections 54, and then into the tubing 40 via the electrically controllablevalves 84. Each electrically controllable valve 84 can be independently adjusted. Thus, forexample, differential pressures can be created between separate controllable well sections 71-75 along the producing interval to prevent excessive inflow rates near the heel 50 of the well20 relative to the toe 52.

The sensors 82 in FIG. 3 are fluid flow sensors adapted to measure the fluid flowbetween the production zone 48 and the tubing interior 104. Flow sensors may be used thatdetect the fluid velocity quantitatively or only the relative rates compared to the sensors in theother well sections. Such sensors may utilize sonie, thermal conduction, or other principlesknown to those skilled in the art. Furthermore, in other embodiments, the sensor or sensors82 in a controllable well section 71-75 may be adapted to measure other physical qualities,including (but not limited to): absolute pressure, differential pressure, fluid density, fluidviscosity, acoustic transmission or reflection properties, température, or Chemical make-up.The fluid flow measurements from the sensors 82 are provided to the communications andcontrol module 80, which further handles the measurements. 19 012224

Preferably the communications and control module 80 comprises a modem andtransmits the flow measurements to the surface computer System within an AC signal (e.g.,spread spectrum modulation) via the tubing 40 and casing 30. Then, the surface computerSystem uses the measurements from one, some, or ail of the sensors 82 in the well 20 tocalculate the pressure drop along the horizontal well section 24, as further described below.Based on the downhole sensor measurements, it is determined whether adjustments to thedownhole valves 84 are needed. If an electrically controllable downhole valve 84 needsadjustment, the surface computer System transmits control commande to the relevantcommunications and control module 80 using the master modem and via the tubing 40 andcasing 30. The communications and control module 80 receives the control commande fromthe surface computer System and Controls the adjustment of the respective valve(s) 84accordingly. In another embodiment, one or more of the communications and controlmodules 80 may comprise an internai logic circuit and/or a microprocessor to locally(downhole) calculate pressure differential based on the sensor measurements, and locallygenerate valve control command signais for adjusting the valves 84.

During operation, pressure draw-down in the well 20 may be accomplished by thesurface tubing valve/orifice 84 in a flowing well, or by artificial lift at the bottom of thevertical section 22. For example, such artificial lift may be provided by gas lift, rod pumping,submersible pumps, or other standard oil field methods.

Effective use of a flow measurement and régulation System provided by controllablewell sections 71-75 dépends on developing a control strategy that relates measured flowvalues to downhole conditions, and that develops an objective function for controlling thesettings of the valves 84 (the flow regulators).

In horizontal well sections, the effect of différences in draw-down pressure onproductivity can be demonstrated by calculating the pressure drop along the horizontalsection 24 resulting from a distributed inflow of fluid from the formation. 20 012224

Example Horizontal Well Analysis: L = length of entire open interval [ fit ] ' N = numberof monitor points (subsections) AL =L/N = spacing of monitors [ft]n = index of subsection ( from toe to heel )

Qn = total flow rate from well [ b/d ]

Pn = total pressure drop over open interval [ psi ]

Ph = head loss from flow in well [( psi/ffc) / (b/d) ] dqf = spécifie inflow rate with uniform profile from formation into well [b/d / fit]Aqf = inflow rate from formation into a subsection of the well [ b/d ]

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

Apn = 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 (2)

With uniform inflow,

Aqf = AL(QN/L)[ 1,1,1,1,...1] (3)

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

Aq„ = AL(Qn/L) [ 1,2, 3,4, ... N ] (4)

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

Ap„ = AL(Aq„)(pH)[l,2,3,4,...N] (5)

Adding the pressure drops in each subsection, the total pressure drop in the well fromthe toe to the successively downstream subsections is pn = Σι" Ap„ (6)

Pn = Σι" AL (Aqn )(pH) (n)(n+l)/2) (7) pn = AL(Aqn)(pH)[l,3,6,10,15,...N(N+l)/2] (8) 21 ASSUMPTIONS: 012224 length of entire open interval .= 2500 ftspacing of monitors = 100 ft total flow rate from well = 2500 b/dspécifie head loss in well = 10'4 psi / b/d / ft

Case 1 : Inflow at Toe of Welt No Inflow along Interval

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 (9)

Case 2: Uniform Inflow

For a well producing uniformly along 25 subdivisions (controllable well sections), thetotal pressure drop in its open interval, as calculated by Equation (8) is: (Aq„)( AL )( pH ) [N(N+l)/2] = (100)(100)(104) (25)(26)/2 = 325 psi. (10)

Case 3: 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 openinterval dépend on flow rate, the inflow profile must be obtained by an itérative calculation.We define the réservoir pressure (pres) as some pressure (p0) above the highest pressure in thewell, that is, the pressure at the toe.

Pres Po + Ptoe (Π)

The pressure différence between the réservoir pressure and the pressure in the well atlocations downstream from the toe is:

Api = (Po + Ptoe) - (Ptoe-Pn) = Po +Pn

Api = po + Σ AL (Aqn )(pH) (n )(n+l) / 2 (12) (13) 22 012224

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

Sum Δρΐ =ΣιΝ Api (14) Δρϊ

Normalized Δρ·, = Pi = _ (15)

Sum Δρϊ =ΣιΝΔρΐ

The inflow rate of each subsection is proportional to this normalized differentialpressure, therefore, the inflow rate of each subsection is: qi = Pi (Qn) Z (AL) (16)

The cumulative flow occurring in the well is:

Qi = Σφ(ΔΌ, (17) and the cumulative pressure drop in the well ffom the toe to the heel is:

Pni = ΣΣ^(Δί)(ρΗ) (18) A second itération is made by substituting these values for the pressure drops intoEquation (12). Convergence is rapid—in this case only a few itérations are needed. Thesecan be carried out by substituting successive values of pni,2,3... in Equation (15). FIG. 4 présents the résulte 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 flowrates in the well are low. For the same total flow rate of 2500 b/d, the uniform inflow caseresults in only about half the total pressure drop (325 psi) compared to Case 1, where the totalpressure drop is 625 psi. When inflow is dépendent on the réservoir pressure (Case 3—Non-Uniform Inflow), even lower pressure drops occur. If the réservoir pressure only slightlyexceeds the well toe pressure, and the pressure drop in the well is large by comparison, thenmost of the inflow occurs near the heel. The lower limit occurs when the réservoir pressure 23 012224 equals the well toe pressure (i.e., p0 = 0) In that case the total pressure drop is 125 psi. Theupper limit, when réservoir pressure becomes large (p0 = °o), results in uniform inflow. FIG. 5 shows the calculated flow rates that resuit from various réservoir inflowconditions. 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.These results demonstrate the high rates that can occur near the heel of a horizontal wellwhen the pressure drop at the toe is small.

In operation, the well 20 is placed in production with the valves 84 (flow regulators)fully open, and the flow rates along the producing interval are measured by the sensors 82and transmitted to the surface computer System for analysis using the methods previouslydescribed. Based on the results of this analysis, the inflow rates in each well section 71-75 ofthe producing interval are determined. Generally, the goal willbe to equalize productioninflow per unit length along the interval, and this is accomplished by transmitting commandsto individual inflow valves to reduce flow in controllable well sections 71-75 that areshowing high inflow. The adjusted flow profile is then derived from the flow measurementsagain, and further adjustments are made to the valves 84 to flatten the production profile andto try to create a pressure profile like that graphed in FIG. 5 for the uniform inflow case, or tomodify a profile into any configuration desired.

The illustrative analysis example described above has been derived for the case of ahorizontal well section 24. It will be clear that similar methods may be applied to a longcompletion in a vertical well or a vertical well section 22, with the same controllable wellsections 71-75 and a similar analysis to dérivé the control strategy from the measurements.

Note that the well management strategy is not assumed to be static. It is to beexpected that as a réservoir is depleted the inflow profile will change. The provision ofpermanent downhole sensors and control devices allows dynamic control of production fromcontrollable well sections to optimize recovery over the full life of the well.

The same methods and principles are applicable to the inverse task of controlledinterval injection, where fluids are passed into the tubing and dispersed selectively into aformation interval using controllable well sections in accordance with the présent invention,for instance in a water flooding process. 24 012224

In other possible embodiments of the présent invention, a controllable well section71-75 may further comprise: additional sensors; additional induction chokes; additionalelectrically controllable valves; a packer valve; a tracer injection module; a tubing valve (e.g.,for varying the flow within a tubing section, such as an application having multiple branchesor laterals); a microprocessor; a logic circuit; a computer System; a rechargeable battery; apower transformer; a relay modem; other electronic components as needed; or anycombination thereof.

The présent invention also may be applied to other types of wells (other thanPetroleum wells), such as a water production well.

It will be appreciated by those skilled in the art having the benefit of this disclosure that thisinvention provides a petroleum production well having controllable well sections, as well asmethods of utilizing such controllable well sections to manage or optimize the wellproduction. It should be understood that the drawings and detailed description herein are tobe 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,design choices, and embodiments apparent to those of ordinary skill in the art, withoutdeparting from the spirit and scope of this invention, as defined by the following daims.Thus, it is intended that the following daims be interpreted to embrace ail such furthermodifications, changes, rearrangements, substitutions, alternatives, design choices, andembodiments.

Claims (30)

1. 25 5 THE INVENTION CLAIMEDIS: 012224

   1. A petroleum well for producing petroleum products comprising: a perforated section having a plurality of perforated sections in at least a portion thereof extending within a wellbore of said well; a production tubing extending within said perforated section; 10 a source of time-varying current at the surface, said current source being electrically connected to at least one of said tubing and said perforated section, such that at least one ofsaid tubing and said perforated section acts as an electrical conductor for transmittingtime-varying electrical current from the surface to a downhole location; and a downholecontrollable well section comprising - 15 a communications and control module, a sensor, and an electrically controllable valve, said communications and control module being electrically connected to atleast one of said tubing and said perforated section, said sensor and said electricallycontrollable valve being electrically connected to said communications and control module, 20 and said electrically controllable valve being adapted to regulate flow between an exterior ofsaid tubing and an interior of said tubing based at least in part on sensor measurements.
2. 2. The petroleum well of claim 1, including an induction choke located about a portionof at least one of said tubing and said perforated section, said induction choke being 25 adapted to route part of said current through said communications and control module by creating a voltage potential within at least one of said tubing and said perforatedcasing between one side of said induction choke and another side of said inductionchoke, wherein said communications and control module is electrically connectedacross said voltage potential. 26 01 2224
3. 3. A petroleum well in accordance with claim 1, wherein said downhole controllablewell section further comprises: a flow inhibitor located within said perforated section and about said tubing such thatfluid flow within said casing from one side of said flow inhibitor to another side of said flowinhibitor is hindered by said flow inhibitor.
4. 4. A petroleum well in accordance with claim 3, wherein said flow inhibitor is aconventional packer.
5. 5. A petroleum well in accordance with claim 3, wherein said flow inhibitor is anelectrically controllable packer comprising an electrically controllable packer valve.
6. 6. A petroleum well in accordance with claim 3, wherein said flow inhibitor is anenlarged portion of said tubing.
7. 7. A petroleum well in accordance with claim 3, wherein said flow inhibitor is a collarlocated about said tubing and within said perforated section.
8. 8. A petroleum well in accordance with claim 1, wherein said sensor is a fluid flow sensor.
9. 9. A petroleum well in accordance with claim 1, wherein said sensor is a fluid pressure sensor.
10. 10. A petroleum well in accordance with claim 1, wherein said sensor is a fluid density sensor. 27 01 2224
11. 11. A petroleum well in accordance with claim 1, wherein said sensor is an acoustic waveform transducer.
12. 12. A petroleum well in accordance with claim 1, further comprising: at least one additional downhole controllable well sections, each of said well sectionsbeing divided from each other by a flow inhibitor, and each well section comprising a sensorand an electrically controllable valve, said electrically controllable valves of said additionalwell sections being adapted to regulate flow between said tubing exterior and said tubinginterior, said flow inhibitors being located within said perforated sections and about otherportions of said tubing such that fluid flow within said perforated sections at each of saidflow inhibitors is hindered by said flow inhibitors.
13. 13. A petroleum well in accordance with claim 1, wherein said communications andcontrol module, said sensor, and said electrically controllable valve are housed within atubing pod, said tubing pod being coupled to said tubing.
14. 14. A petroleum well in accordance with claim 1, wherein said communications and control module includes a modem.
15. 15. A method of producing petroleum from a petroleum well, comprising the steps of:providing a plurality of downhole controllable well sections of said wells a number of said well sections comprising a communications and control module, a sensor, an electricallycontrollable valve, and a flow inhibitor, said flow inhibitor being located within a well casingand about a portion of a production tubing of said well, said communications and controlmodule being electrically connected to at least one of said tubing and said casing, and saidelectrically controllable valve and said sensor being electrically connected to saidcommunications and control module; 28 012224 hindering fluid flow between said well sections within said casing with said flowinhibitors; measuring a fluid characteristic at each of said well sections with a respective sensor;regulating fluid flow into said tubing at one or more of said well sections with its respective electrically controllable valve, based on said fluid characteristic measurements; and producing petroleum products from said well via said tubing.
16. 16. A method in accordance with claim 15, further comprising the steps of: inputting a time-varying current into at least one of said tubing and said casing from acurrent source at the surface; impeding said current with an induction choke located about at least one of saidtubing and said casing; creating a voltage potential between one side of said induction choke and another sideof said induction choke within at least one of said tubing and said casing; routing said current through at least one of said communications and control modulesat said voltage potential using said induction choke; and powering said at least one of said communications and control modules using saidvoltage potential and said current from at least one of said tubing and said casing.
17. 17. A method in accordance with claim 16, further comprising the step of communieating with said at least one of said communications and control modules via said current and via at least one of said tubing and said casing.
18. 18. A method in accordance with claim 15, further comprising the steps of:transmitting said fluid measurements to a computer System at the surface using said communications and control module via at least one of said tubing and said casing; 29 012224 calculating a pressure drop along said well sections, with said computer System, usingsaid fluid measurements; determining if adjustments are needed for said electrically controllable valves of saidwell sections; sending command signais to said communications and control modules of said wellsections needing valve adjustment; and adjusting a position of said electrically controllable valve via said communicationsand control module for each of said well sections needing valve adjustment.
19. 19. A method in accordance with claim 15, wherein said steps of: regulating fluid flow at each of said well sections to provide a substantially uniformproductivity from said at least one petroleum production zone across said well sections; and increasing recovery efficiency from said at least one petroleum production zone.
20. 20. A method in accordance with claim 15, further comprising the step of hindering cross-flow from one permeability layer of said at least one petroleum production zone having a firstfluid pressure to another permeability layer of said at least one petroleum production zonehaving a second fluid pressure, wherein said first pressure is greater than said second pressure.
21. 21. A method in accordance with claim 15, further comprising the step of preventingprématuré gas breakthrough from gas coning down into said at least one petroleumproduction zone.
22. 22. A method in accordance with claim 15, further comprising the step of preventingprématuré water breakthrough from water coning up into said at least one petroleumproduction zone. 30 012224 23. ^ A method in accordance with claim 15, further comprising the step of improving aproductivity profile of at least one petroleum production zone.
23. 24. A method in accordance with claim 15, further comprising the step of extending aproduction life of at least one petroleum production zone.
24. 25. A method in accordance with claim 15, further comprising the step of measuring fluidflow at one of said well sections with a fluid flow sensor.
25. 26. A method in accordance with claim 16, further comprising the step of measuring fluidpressure at one of said well sections with a pressure sensor.
26. 27. A method in accordance with claim 15, further comprising the step of measuring fluiddensity at one of said well sections with a fluid density sensor.
27. 28. A method of controllably injecting fluid into a formation with a well, comprising thesteps of: providing a plurality of controllable well sections in said well, each of said wellsections comprising a communications and control module, a sensor, and an electricallycontrollable valve, and a flow inhibitor, said communications and control module beingelectrically connected to at least one of said tubing and said casing, said electricallycontrollable valve and said sensor being electrically connected to said communications andcontrol module, and said flow inhibitor being located within a well casing and about a portionof a tubing string of said well; hindering fluid flow between said well sections within said casing with said flowinhibitors; measuring fluid characteristic at each of said well sections with its respective sensor; controllably injecting fluid into said tubing; and 31 01 222 4 regulating fluid flow from said tubing interior into said formation at one or more ofsaid well sections with its respective electrically controllable valve, based on said fluid measurements.
28. 29. A method in accordance with claim 28, further comprising the steps of:inputting AC signal into at least one of said tubing and said casing from a current source at the surface; impeding said AC signal with an induction choke located about at least one of saidtubing and said casing; routing said AC signal through at least one of said communications and controlmodules; and powering said at least one of said communications and control modules using said ACsignal from at least one of said tubing and said casing.
29. 30. A method in accordance with claim 29, further comprising the step of communicatingwith said at least one of said communications and control modules via said AC signal and viaat least one of said tubing and said casing.
30. 31. A method in accordance with claim 28, further comprising the steps of:transmitting said fluid characteristic measurements to a computer System at the surface using said communications and control module via at least one of said tubing and saidcasing; calculating a pressure drop along said well sections, with said computer System, usingsaid fluid characteristic measurements; determining if adjustments are needed for said electrically controllable valves of said well sections; 32 012224 5 sending command signais to said communications and control modules of said well sections needing valve adjustment; and also if valve adjustments are needed, adjusting a position of said electricallycontrollable valve via said communications and control module for each of said well sectionsneeding valve adjustment. 10 32. A method in accordance with claim 28, wherein said step of regulating fluid flow at each of said well sections to provide a substantially uniform injection of fluid from saidtubing into said formation across said well sections.