Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
  • E21B43/121—Lifting well fluids
  • E21B43/122—Gas lift
  • E21B43/123—Gas lift valves
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
  • E21B17/003—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings with electrically conducting or insulating means
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B34/00—Valve arrangements for boreholes or wells
  • E21B34/06—Valve arrangements for boreholes or wells in wells
  • E21B34/066—Valve arrangements for boreholes or wells in wells electrically actuated
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B34/00—Valve arrangements for boreholes or wells
  • E21B34/06—Valve arrangements for boreholes or wells in wells
  • E21B34/08—Valve arrangements for boreholes or wells in wells responsive to flow or pressure of the fluid obtained
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B34/00—Valve arrangements for boreholes or wells
  • E21B34/16—Control means therefor being outside the borehole
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/14—Obtaining from a multiple-zone well
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
  • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/12—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling
  • E21B47/13—Means for transmitting measuring-signals or control signals from the well to the surface, or from the surface to the well, e.g. for logging while drilling by electromagnetic energy, e.g. radio frequency
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
  • E21B2200/02—Down-hole chokes or valves for variably regulating fluid flow

Definitions

• the present invention relates to a petroleum well for producing petroleum products.
• the present invention relates to systems and methods of electrically controlling downhole well interval inflow and/or injection for producing petroleum products.
• the open intervals typically include a number of geologic layers having a variety of petrophysical properties and initial reservoir conditions. Variations in permeability and initial reservoir pressure especially, result in uneven depletion of layers, if the 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 may even cross-flow into lower pressure layers.
• the open completion interval In horizontal wells, the open completion interval is usually contained in a single geologic layer. However, uneven inflow can result from a pressure drop along the well. This effect is particularly evident in long completion intervals where the reservoir pressure is nearly equal to the pressure in the well at the far end (the toe). In such a case, almost no inflow occurs at the toe. At the other end of the open interval near the vertical part of the well (the heel), the greater difference between the reservoir pressure and the pressure in the well results in higher inflow rates there. High inflow rates near the heel can lead to early gas breakthrough from gas coning down, or early water breakthrough from water coning up. Productivity profiles of vertical wells are described by the steady state Darcy flow equation for radial flow:
• the former grain mineral framework — is not expected to change the productivity profile very much during the life of the well because the grain framework remains unchanged, except for compaction. But compaction can equalize layer permeabilities.
• the effects of fluid saturation on permeability lead to poor productivity profiles because, for example, a high permeability layer is likely to have a high specific fluid saturation, which makes that layer even more productive. During the life of a well these saturation effects can lead to even poorer profiles because, for example, gas or water breakthrough into a well results in increasing breakthrough fluid saturation and even higher productivity of that fluid relative to the other layers.
• Productivity profiles in horizontal wells may be affected by layering if the well intersects dipping beds or if the horizontal well is slightly inclined and crosses an impermeable bed. However, the major effect is expected to be the difference in draw-down pressure between the toe and the heel.
• Wells may also be used for fluid injection.
• water flooding is sometimes used to displace hydrocarbons in the formation towards producing wells.
• water flooding it is desirable to have uniform injection.
• fluid injection the same issues arise with respect to ensuring uniform injection as those mentioned above for seeking uniform inflow, and for the same reasons.
• a petroleum well for producing petroleum products comprises a well casing, a production tubing, a source of time- varying current, and a downhole controllable well section.
• the well casing extends within a wellbore of the well, and the production tubing extends within the casing.
• the source of time- varying current is at the surface, and electrically connected to the tubing and/or the casing, such that the tubing and/or the casing acts as an electrical conductor for transmitting time- varying electrical current from the surface to a downhole location.
• the downhole controllable well section comprises a communications and control module, a sensor, an electrically controllable valve, and an induction choke.
• the communications and control module is electrically connected to the tubing and/or the casing.
• the sensor and the electrically controllable valve are electrically connected to the communications and control module.
• the electrically controllable valve is adapted to regulate flow between an exterior of the tubing and an interior of the tubing.
• the induction choke is located about a portion of the tubing and/or the casing.
• the induction choke is adapted to route part of the current through the communications and control module by creating a voltage potential within the tubing and/or the casing between one side of the induction choke and another side of the induction choke.
• the communications and control module is electrically connected across this voltage potential.
• the downhole controllable well section may further comprise a flow inhibitor located within the casing and about another portion of the tubing such that fluid flow within the casing from one side of the flow inhibitor to another side of the flow inhibitor is hindered by the flow inhibitor.
• a flow inhibitor may be used to define a boundary between the well sections.
• the sensor may be a fluid flow sensor, a fluid pressure sensor, a fluid density sensor, or an acoustic waveform transducer.
• a method of producing petroleum from a petroleum well comprises the following steps, the order of which may vary: (i) providing a plurality of downhole controllable well sections of the well for at least one petroleum production zone, each of the well sections comprising a communications and control module, a flow sensor, an electrically controllable valve, and a flow inhibitor, the flow inhibitor being located within a well casing and about a portion of a production tubing of the well, the communications and control module being electrically connected to the tubing and/or the casing, and the electrically controllable valve and the flow sensor being electrically connected to the communications and control module; (ii) hindering fluid flow between the well sections within the casing with the flow inhibitor; (iii) measuring fluid flow between the at least one petroleum production zone and an interior of the tubing at each of the well sections with its respective flow sensor; (iv) regulating fluid flow between the at least one petroleum production zone and the interior of the tubing at each of the well sections with its
• 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 at the surface; (vii) impeding the current with an induction choke located about the tubing and/or the casing; (viii) creating a voltage potential between one side of the induction choke and another side of the induction choke within the tubing and/or the casing; (ix) routing the current through at least one of the communications and control modules at the voltage potential using the induction choke; and (x) powering at least one of the communications and control modules using the voltage potential and the current from the tubing and/or the casing.
• 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 the communications and control module via the tubing and/or the casing; (xii) calculating a pressure drop along the well sections, with the computer system, and using the fluid flow measurements; (xiii) determining if adjustments are needed for the electrically controllable valves of the well sections; (xiv) if valve adjustments are needed, sending command signals to 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 electrically controllable valve via the communications and control module for each of the well sections needing valve adjustment.
• a method of controllably injecting fluid into a formation with a well comprises the following steps, the order of which may vary: (i) providing a plurality, of controllable well sections of the well for the formation, each of the well sections comprising a communications and control module, a flow sensor, and an electrically controllable valve, and a flow inhibitor, the communications and control module being electrically connected to the tubing and/or the casing, the electrically controllable valve and the flow sensor being electrically connected to the communications and control module, and the flow inhibitor being 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 well sections with its respective flow sensor; (iv) regulating fluid flow from the tubing interior into the formation at each of the well sections with its respective electrically controllable valve
• 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 at the surface; (vii) impeding the current with an induction choke located about the tubing and/or the casing; (viii) creating a voltage potential between one side of the induction choke and another side of the induction choke within the tubing and/or the casing; (ix) routing the current through at least one of the communications and control modules at the voltage potential using the induction choke; and (x) powering the at least one of the communications and control modules using the voltage potential and the current from the tubing and/or the casing.
• 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 the communications and control module via the tubing and/or the casing; (xii) calculating a pressure drop along the well sections, with the computer system, using the fluid flow measurements; (xiii) determining if adjustments are needed for the electrically controllable valves of the well sections; (xiv) if valve adjustments are needed, sending command signals to 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 electrically controllable valve via the communications and control module for each of the well sections needing valve adjustment.
• the Related Applications describe ways to deliver electrical power to downhole devices, and to provide bi-directional communications between the surface and each downhole device individually.
• the downhole devices may contain sensors or transducers to measure downhole conditions, such as pressure, flow rate, liquid density, or acoustic waveforms. Such measurements can be transmitted to the surface and made available in near-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 individual device downhole.
• Downhole devices to measure and control inflow or injection over long interval completions are placed within well sections. The measured flow rates are used to control accompanying devices, which are used to regulate inflow from or injection into subsections of the completion.
• FIG. 1 A is schematic of an upper portion of a petroleum well in accordance with a preferred embodiment of the present invention
• FIG. IB is schematic of an upper portion of a petroleum well in accordance with another preferred embodiment of the present invention
• FIG. 2 is a schematic of a downhole portion of a petroleum production well in accordance with a preferred embodiment of the present invention
• FIG. 3 is an enlarged view of a portion of FIG. 2 showing a well section of the petroleum production well;
• FIG. 4 graphs cumulative pressure drop along production tubing as a function of distance along the tubing for a range of differences between reservoir pressure and well toe pressure
• FIG. 5 graphs relative inflow rate as a function of distance along the tubing for a range of differences between the reservoir pressure and the pressure at the toe of the well.
• a "piping structure" can be one single pipe, a tubing string, a well casing, a pumping rod, a series of interconnected pipes, rods, rails, trusses, lattices, supports, a branch or lateral extension of a well, a network of interconnected pipes, or other similar structures known to one of ordinary skill in the art.
• a preferred embodiment makes use of the invention in the context of a petroleum well where the piping structure comprises tubular, metallic, electrically-conductive pipe or tubing strings, but the invention is not so limited.
• an electrically conductive piping structure is one that provides an electrical conducting path from a first portion where a power source is electrically connected to a second portion where a device and/or electrical return is electrically connected.
• the piping structure will typically be conventional round metal tubing, but the cross-section geometry of the 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 piping structure.
• a piping structure must have an electrically conductive portion extending from a first portion of the piping structure to a second portion of the piping structure, wherein' the first portion is distally spaced from the second portion along the piping structure.
• modem is used herein to generically refer to any communications device for transmitting and/or receiving electrical communication signals via an electrical conductor (e.g., metal).
• modem as used herein is not limited to the acronym for a modulator (device that converts a voice or data signal into a form that can be transmitted)/demodulator (a device that recovers an original signal after it has modulated a high frequency carrier).
• modem as used herein is not limited to conventional computer modems that convert digital signals to analog signals and vice versa (e.g., to send digital data signals over the analog Public Switched Telephone Network).
• a sensor outputs measurements in an analog format
• measurements may only need to be modulated (e.g., spread spectrum modulation) and transmitted—hence no analog/digital conversion needed.
• a relay/slave modem or communication device may only need to identify, filter, amplify, and/or retransmit a signal received.
• valve generally refers to any device that functions to regulate the flow of a fluid.
• valves include, but are not limited to, bellows-type gas-lift valves and controllable gas-lift valves, each of which may be used to regulate the flow of lift gas into a tubing string of a well.
• the internal and/or external workings of valves can vary greatly, and in the present application, it is not intended to limit the valves described to any particular configuration, so long as the valve functions to regulate flow.
• Some of the various types of flow regulating mechanisms include, but are not limited to, ball valve configurations, needle valve configurations, gate valve configurations, and cage valve configurations. The methods of installation for valves discussed in the present application can vary widely.
• electrically controllable valve as used herein generally refers to a "valve"
• sensor refers to any device that detects, determines, 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 not limited to: temperature, pressure (both absolute and differential), flow rate, seismic data, acoustic data, pH level, salinity levels, valve positions, or almost any other physical data.
• the phrase "at the surface” as used herein refers to a location that is above about fifty feet deep within the Earth.
• the phrase “at the surface” does not necessarily mean sitting on the ground at ground level, but is used more broadly herein to refer to a location that is often easily or conveniently accessible at a wellhead where people may be working.
• “at the surface” can be on a table in a work shed that is located on the ground at the well platform, it can be on an ocean floor or a lake floor, it can be on a deep-sea oil rig platform, or it can be on the 100th floor of a building.
• the term “surface” may be used herein as an adjective to designate a location of a component or region that is located “at the surface.”
• a "surface” computer would be a computer located "at the surface.”
• downhole refers to a location or position below about fifty feet deep within the Earth.
• downhole is used broadly herein to refer to a location that is often not easily or conveniently accessible from a wellhead where people may be working.
• a “downhole” location is often at or proximate to a subsurface petroleum production zone, irrespective of whether the production zone is accessed vertically, horizontally, or any other angle therebetween.
• the descriptors "upper,” “lower,” “uphole,” and “downhole” are relative and refer to distance along hole depth from the surface, which in deviated or horizontal wells may or may not accord with vertical elevation measured with respect to a survey datum.
• wireless means the absence of a conventional, insulated wire conductor e.g. extending from a downhole device to the surface. Using the tubing and/or casing as a conductor is considered “wireless.”
• FIG. 1A is schematic of an upper portion of a petroleum well 20 in accordance with a preferred embodiment of the present invention.
• a well casing 30 and the tubing string 40 act as electrical conductors for the system.
• An insulating tubing joint 56 is incorporated at the wellhead to electrically insulate the tubing 40 from casing 30.
• the insulators 58 of the joint 56 prevent an electrical short circuit between lower sections of the tubing 40 and casing 30 at the hanger 34.
• a surface computer system 36 comprising a master modem 37 and a source of time- varying current 38 is electrically connected to the tubing string 40 below the hanger 34 by a first source terminal 39.
• the first source terminal 39 is insulated from the hanger 34 where it passes through it.
• a second source terminal 41 is electrically connected to the well casing 30, either directly (as in FIG. 1 A) or via the hanger 34 (arrangement not shown).
• the time-varying current source 38 provides the time-varying electrical current, which carries power and communication signals downhole.
• the time-varying electrical current is preferably alternating current (AC), but it can also be a varying direct current (DC).
• the communication signals can be generated by the master modem 37 and embedded within the current produced by the source 38.
• the communication signal is a spread spectrum signal, but other forms of modulation can be used in alternative.
• an upper induction choke 43 can be placed about the tubing 40 above the electrical connection location for the first source terminal 39 to the tubing.
• the upper induction choke 43 comprises a ferromagnetic material and is located generally concentrically about the tubing 40.
• the upper induction choke 43 functions based on its size, geometry, spatial relationship to the tubing 40, and magnetic properties.
• the upper choke 43 acts as an inductor inhibiting the flow of the current between the tubing 40 below the upper choke 43 and the tubing 40 above the upper choke 43 due to the magnetic flux created within the upper choke 43 by the current.
• most of the current is routed down the tubing 40 (i.e., downhole), rather than shorting across the hanger 45 to the casing 30.
• FIG. 2 is schematic of a downhole portion of a petroleum production well 20 in accordance with a preferred embodiment of the present invention.
• the well 20 has a vertical section 22 and a horizontal section 24.
• the well has a well casing 30 extending within a wellbore and through a formation 32, and a production tubing 40 extends within the well casing.
• the well 20 shown in FIG. 2 is similar to a conventional well in construction, but with the incorporation of the present invention.
• the vertical section 22 in this embodiment incorporates a packer 44 which is furnished with an electrically insulating sleeve 76 such that the tubing 40 is electrically insulated from casing 30.
• the vertical section 22 is also furnished with a gas-lift valve 42 to provide artificial lift for fluids within the tubing using gas bubbles 46.
• the vertical portion 22 can further vary to form many other possible embodiments.
• the vertical portion 22 may incorporate one or more electrically controllable gas-lift valves, one or more induction chokes, and/or one or more controllable packers comprising electrically controllable packer valves, as described in the Related Applications.
• the horizontal section 24 of the well 20 extends through a petroleum production zone
• the casing 30 has perforated sections 54 that allow fluids to pass from the production zone 48 into the casing 30.
• Numerous flow inhibitors 61-65 are placed along the horizontal section 24 in the annular space 68 between the casing 30 and the tubing 40. The purpose of these flow inhibitors 61-65 is to hinder or prevent fluid flow along the annulus 68 within the casing 30, and to thus separate or form a series of controllable well sections 71-75. In the embodiment shown in FIG.
• the flow inhibitors 61-65 are conventional packers with electrically insulating sleeves to maintain electrical isolation between tubing 104 and casing 54 (functionally equivalent to packer 44 with sleeve 76), which themselves are known in the art.
• any of the flow inhibitors 61-65 can be provided by any other way that makes the cross-sectional area of the annular space 68 (between the casing 30 and the tubing 40) small compared to the internal cross-sectional area of the tubing 40, while maintaining electrical isolation between tubing and casing.
• the flow inhibitors 61-65 do not necessarily need to form fluid-tight seals between the well sections 71-75, as conventional packers typically do.
• any of the flow inhibitors 61-65 may be (but is not limited to being): a conventional packer; a controllable packer comprising an electrically controllable packer valve, as described in the Related Applications; a close-fitting tubular section; an enlarged portion of tubing; a collar about the tubing; or an inflatable collar about the tubing.
• a controllable packer as a flow inhibitor can provide variable control over the fluid communication among well sections — such controllable packers are further described in the Related Applications.
• each controllable well section 71-75 comprises a communications and control module 80, a sensor 82, and an electrically controllable valve 84.
• each well section 71-75 further comprises a ferromagnetic induction choke 90.
• the number of downhole induction chokes 90 may vary. For example, there may be one downhole induction choke 90 for two or more well sections 71-75, and hence some of the well sections would not comprise an induction choke.
• the tubing 40 acts as a piping structure and the casing 30 acts as an electrical return to form an electrical circuit in the well 20.
• the tubing 40 and casing 30 are used as electrical conductors for communications signals between the surface (e.g., a surface computer) and the downhole electrical devices within the controllable well sections 71-75.
• the downhole induction chokes 90 comprise a ferromagnetic material and are unpowered.
• the downhole chokes 90 are located about the tubing 40, and each choke acts as a large inductor to AC in the well circuit formed by the tubing 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.
• the material composition of the chokes 43, 90 may vary, as long as they exhibit the requisite magnetic properties needed to act as an inductor to the time- varying current, which will depend (in part) on the size of the current.
• FIG. 3 is an enlarged view of a controllable well section 71 from FIG. 2. Focusing on the well section 71 of FIG. 3 as an example, the communications and control module 80 is electrically connected to the tubing 40 for power and/or communications. A first device terminal 91 of the communications and control module 80 is electrically connected to the tubing 40 on a source-side 94 of the downhole induction choke 90. And, a second device terminal 92 of the communications and control module 80 is electrically connected to the tubing 40 on an electrical-return-side 96 of the downhole induction choke 90.
• the communications and control module 80 can be electrically connected across the voltage potential between the tubing 40 and the casing 30. If in an enhanced form one or more of the flow inhibitors 61-65 is a packer comprising an electrically powered device (e.g., sensor, electrically controllable packer valve), the electrically powered device of the packer will likely also be electrically connected across the voltage potential created by the downhole choke 90, either directly or via a nearby communications and control module 80.
• an electrically powered device e.g., sensor, electrically controllable packer valve
• the packer 65 at the toe 52 provides an electrical connection between the tubing 40 and the casing 30, and the casing 30 is electrically connected to the surface computer system (not shown) to complete the electrical circuit formed by the well 20. Because in this embodiment it is not desirable to have the tubing 40 electrically shorted to casing 30 between the surface and the toe 52, it is necessary to electrically insulate part of the packers 44, 61, 62, 63, 64 between the surface and the toe so that they do not act as a shorts between the tubing 40 and the casing 30.
• a tubing pod 100 holds or contains the communications and control module 80, sensors 82, and electrically controllable valves 84 together as one module for ease of handling and installation, as well as to protect these components from the surrounding environment.
• the components of the tubing pod 100 can be separate (i.e., no tubing pod) or combined in other combinations.
• multiple tubing pods may share a single communications and control module.
• the tubing pod 100 shown in FIG. 3 has two sensors 82 and two electrically controllable valves 84.
• Each valve 84 has an electric motor 102 coupled thereto, via a set of gears, for opening, closing, adjusting, or continuously throttling the valve position in response to command signals from the communications and control module 80.
• the electrically 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.
• the controlled-opening orifice of the tubing created by the valve 84 may be controlled by the sensor 82, and may be actuated by the natural hydraulic power in the flowing well, by stored electrical power, or other ways.
• the orifice of the valve 84 may comprise a standard ball valve, a rotating sleeve, a linear sleeve valve, or any other device suitable to regulate flow. It may never be necessary to effect a complete shut-off or closing of the valve 84, but if needed, that type of valve may be used.
• fluids e.g., oil
• Each electrically controllable valve 84 can be independently adjusted.
• 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 well 20 relative to the toe 52.
• the sensors 82 in FIG. 3 are fluid flow sensors adapted to measure the fluid flow between the production zone 48 and the tubing interior 104. Flow sensors may be used that detect the fluid velocity quantitatively or only the relative rates compared to the sensors in the other well sections. Such sensors may utilize sonic, thermal conduction, or other principles known to those skilled in the art. Furthermore, in other embodiments, the sensor or sensors 82 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, fluid viscosity, acoustic transmission or reflection properties, temperature, or chemical make-up. The fluid flow measurements from the sensors 82 are provided to the communications and control module 80, which further handles the measurements.
• the communications and control module 80 comprises a modem and transmits 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 computer system uses the measurements from one, some, or all of the sensors 82 in the well 20 to calculate the pressure drop along the horizontal well section 24, as further described below. Based on the downliole sensor measurements, it is determined whether adjustments to the downhole valves 84 are needed. If an electrically controllable downhole valve 84 needs adjustment, the surface computer system transmits control commands to the relevant communications and control module 80 using the master modem and via the tubing 40 and casing 30.
• AC signal e.g., spread spectrum modulation
• the communications and control module 80 receives the control commands from the surface computer system and controls the adjustment of the respective valve(s) 84 accordingly.
• one or more of the communications and control modules 80 may comprise an internal logic circuit and/or a microprocessor to locally (downhole) calculate pressure differential based on the sensor measurements, and locally generate valve control command signals for adjusting the valves 84.
• pressure draw-down in the well 20 may be accomplished by the surface tubing valve/orifice 84 in a flowing well, or by artificial lift at the bottom of the vertical section 22.
• 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 regulation system provided by controllable well sections 71-75 depends on developing a control strategy that relates measured flow values to downhole conditions, and that develops an objective function for controlling the settings of the valves 84 (the flow regulators).
• N number of monitor points (subsections)
• n index of subsection ( from toe to heel )
• QN total flow rate from well [b/d]
• n 1,2,3,4,...N (2)
• the inflow rate into the well is proportional to the difference between the reservoir pressure and the pressure in the well. Because the pressures in the well along the open interval depend on flow rate, the inflow profile must be obtained by an iterative calculation.
• the reservoir pressure (p res ) as some pressure (p 0 ) above the highest pressure in the well, that is, the pressure at the toe.
• the cumulative flow and cumulative pressure drop along the tubing may be calculated by summing the inflow differential pressures (p 0 + p ⁇ ) and normalizing the subsection differential pressures with that sum:
• the cumulative flow occurring in the well is:
• Equation (12) A second iteration is made by substituting these values for the pressure drops into Equation (12). Convergence is rapid — in this case only a few iterations are needed. These can be carried out by substituting successive values of p n ⁇ ,2, 3 ... in Equation (15).
• FIG. 4 presents the results of these pressure drop calculations for several inflow conditions.
• the cumulative pressure drop along the tubing is large since each section of the pipe experiences the maximum pressure drop.
• the uniform inflow case results in only about half the total pressure drop (325 psi) compared to Case 1, where the total pressure drop is 625 psi.
• inflow is dependent on the reservoir pressure (Case 3 — Non- Uniform Inflow), even lower pressure drops occur.
• the reservoir pressure only slightly exceeds the well toe pressure, and the pressure drop in the well is large by comparison, then most of the inflow occurs near the heel.
• FIG. 5 shows the calculated flow rates that result from various reservoir inflow conditions.
• the flow rates that occur along the horizontal well section under the conditions given above may be normalized with respect to the flow rates in a well with uniform inflow.
• 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 82 and transmitted to the surface computer system for analysis using the methods previously described. Based on the results of this analysis, the inflow rates in each well section 71-75 of the producing interval are determined. Generally, the goal will be to equalize production inflow per unit length along the interval, and this is accomplished by transmitting commands to individual inflow valves to reduce flow in controllable well sections 71-75 that are showing high inflow. The adjusted flow profile is then derived from the flow measurements again, and further adjustments are made to the valves 84 to flatten the production profile and to try to create a pressure profile like that graphed in FIG. 5 for the uniform inflow case, or to modify a profile into any configuration desired.
• the valves 84 flow regulators
• 71-75 may further comprise: additional sensors; additional induction chokes; additional electrically 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 branches or laterals); a microprocessor; a logic circuit; a computer system; a rechargeable battery; a power transformer; a relay modem; other electronic components as needed; or any combination thereof.
• additional sensors additional induction chokes; additional electrically 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 branches or laterals); a microprocessor; a logic circuit; a computer system; a rechargeable battery; a power transformer; a relay modem; other electronic components as needed; or any combination thereof.

Landscapes

• Engineering & Computer Science (AREA)
• Geology (AREA)
• Life Sciences & Earth Sciences (AREA)
• Mining & Mineral Resources (AREA)
• Physics & Mathematics (AREA)
• Geochemistry & Mineralogy (AREA)
• General Life Sciences & Earth Sciences (AREA)
• Environmental & Geological Engineering (AREA)
• Fluid Mechanics (AREA)
• Remote Sensing (AREA)
• Geophysics (AREA)
• Mechanical Engineering (AREA)
• Electromagnetism (AREA)
• Pipeline Systems (AREA)
• Geophysics And Detection Of Objects (AREA)
• Loading And Unloading Of Fuel Tanks Or Ships (AREA)
• Measuring Fluid Pressure (AREA)
• Percussion Or Vibration Massage (AREA)
• Devices For Medical Bathing And Washing (AREA)

Applications Claiming Priority (3)

Publications (1)

Family

ID=22684776

Family Applications (1)

Country Status (9)

Cited By (1)

Families Citing this family (31)

Family Cites Families (13)

• 2001
  • 2001-03-02 OA OA1200200274A patent/OA12224A/en unknown
  • 2001-03-02 EP EP01924112A patent/EP1259707A1/de not_active Withdrawn
  • 2001-03-02 CA CA002401709A patent/CA2401709C/en not_active Expired - Fee Related
  • 2001-03-02 RU RU2002126207/03A patent/RU2258799C2/ru not_active IP Right Cessation
  • 2001-03-02 MX MXPA02008579A patent/MXPA02008579A/es active IP Right Grant
  • 2001-03-02 WO PCT/US2001/006802 patent/WO2001065063A1/en active IP Right Grant
  • 2001-03-02 AU AU5079501A patent/AU5079501A/xx active Pending
  • 2001-03-02 BR BRPI0108874-2A patent/BR0108874B1/pt not_active IP Right Cessation
  • 2001-03-02 AU AU2001250795A patent/AU2001250795B2/en not_active Ceased
• 2002
  • 2002-08-30 NO NO20024140A patent/NO330961B1/no not_active IP Right Cessation

Non-Patent Citations (1)

Also Published As

Similar Documents

Legal Events