WO2012148628A2 - Générateur d'énergie électrostatique induite par l'écoulement destiné à être utilisé en fond de puits dans les forages pétroliers et gaziers - Google Patents

Générateur d'énergie électrostatique induite par l'écoulement destiné à être utilisé en fond de puits dans les forages pétroliers et gaziers Download PDF

Info

Publication number
WO2012148628A2
WO2012148628A2 PCT/US2012/031432 US2012031432W WO2012148628A2 WO 2012148628 A2 WO2012148628 A2 WO 2012148628A2 US 2012031432 W US2012031432 W US 2012031432W WO 2012148628 A2 WO2012148628 A2 WO 2012148628A2
Authority
WO
WIPO (PCT)
Prior art keywords
tubular
flow
membrane
electrical
electrically
Prior art date
Application number
PCT/US2012/031432
Other languages
English (en)
Other versions
WO2012148628A3 (fr
Inventor
Luis Phillipe TOSI
Holley Mitchell Cornette
David Reuel Underdown
Original Assignee
Chevron U.S.A. Inc.
Priority date (The priority date is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the date listed.)
Filing date
Publication date
Priority claimed from US13/094,964 external-priority patent/US8511373B2/en
Priority claimed from US13/094,954 external-priority patent/US8714239B2/en
Application filed by Chevron U.S.A. Inc. filed Critical Chevron U.S.A. Inc.
Priority to EP12776615.2A priority Critical patent/EP2702241A4/fr
Priority to BR112013027083A priority patent/BR112013027083A2/pt
Priority to CA2833243A priority patent/CA2833243A1/fr
Priority to AU2012250159A priority patent/AU2012250159A1/en
Publication of WO2012148628A2 publication Critical patent/WO2012148628A2/fr
Publication of WO2012148628A3 publication Critical patent/WO2012148628A3/fr

Links

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
    • E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
    • E21B41/0085—Adaptations of electric power generating means for use in boreholes
    • 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
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/02—Subsoil filtering
    • E21B43/08—Screens or liners
    • E21B43/086—Screens with preformed openings, e.g. slotted liners
    • 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

Definitions

  • the field is the harnessing of electrostatic energy, and specifically to utilizing flow-induced electrostatic energy to power electrical devices in the subterranean environment of an oil and/or gas well.
  • Oil and gas wells have significant downhole electrical power needs. Pumps, valves, sensors, and the like— all require power to function. This power can be consumed continuously and/or in discrete intervals. This power is typically supplied to a downhole well environment via tubing encapsulated cable (from the surface) or in situ via batteries. Unfortunately, either scenario requires the frequent insertion and removal of equipment from the well which, in turn, leads to a reduction in efficiency.
  • the present invention is directed to processes (i.e., methods, the two terms being used interchangeably herein) for harnessing flow-induced electrostatic energy in an oil and/or gas well and using this energy to power electrical devices (e.g., flowmeters, electrically-actuated valves, sliding sleeves, etc.) downhole (i.e., in the well, at depth).
  • electrical devices e.g., flowmeters, electrically-actuated valves, sliding sleeves, etc.
  • the present invention is also directed to corresponding systems through which such methods are (or can be) implemented. Methods and systems will each be generally characterized as being of either a first type or a second type, depending upon how the electrostatic energy is developed within the well.
  • the present invention is directed to methods (of a first type) of powering devices in a petroleum well through the generation of electrostatic energy downhole, the petroleum well originating at a geological surface, having variable or non-variable orientation along the length of the well, and comprising a plurality of tubular segments disposed therewithin and connected in series along the well length, said method comprising the steps of: (a) flowing a substantially non-conductive hydrocarbon-based fluid, as a flowstream, through a designated tubular length that is electrically-isolated from adjacent tubular segments to which it is connected, wherein the non-conductive hydrocarbon-based fluid has a relative permittivity of between 2 and 40; (b) generating a net, steady-state electrostatic potential between the flowstream and said designated tubular length; (c) harvesting electrical energy from the electrostatic potential via a ground electrode in electrical contact with the flowstream and an electrical lead in electrical contact with the designated tubular length; and (d) using the electrical energy harvested in Step (c) to power one
  • the present invention is directed toward systems of a first type, such systems being operable for powering devices in a petroleum well through the generation of electrostatic energy downhole and generally comprising: a wellbore originating at a geological surface and extending from said surface into a geological formation; a plurality of tubular segments disposed within the wellbore, wherein said tubular segments are useful in conveying hydrocarbon-based fluids out of said wellbore; at least one electrically-isolated tubular segment that is electrically isolated from any adjoining segments (e.g., via insulation or electrically-insulating surface coatings), wherein said electrically-isolated tubular segment includes a high friction surface on its interior; at least one device-bearing tubular segment comprising at least one device that can be usefully employed downhole; at least one electrical lead establishing connectivity between the at least one electrically-isolated tubular segment and the at least one device-bearing tubular segment; a flow of substantially non- conductive hydrocarbon-based fluid,
  • the present invention is directed to methods (of a second type) of powering devices in a petroleum well through the generation of electrostatic energy downhole, the petroleum well originating at a geological surface and being operable for the production of oil, natural gas, or mixtures thereof, said methods generally comprising the steps of: (a') flowing a substantially non-conductive hydrocarbon-based fluid, as a flowstream, through a substantially insulating membrane; (b') generating a net, steady-state electrostatic potential between the flowstream and said membrane, wherein the membrane comprises a plurality of flow channels through which the substantially non-conductive hydrocarbon-based fluid can pass, and wherein at least a majority of said flow channels have an effective diameter of at least about 500 nm and at most about 200 ⁇ ; (c') harvesting electrical energy from the electrostatic potential via a ground electrode in electrical contact with the flowstream and an electrical lead in electrical contact with the membrane; and (d') using the electrical energy harvested in Step (c') to power one or more devices downhole.
  • the present invention is directed to systems of a second type for powering devices in a petroleum well through the generation of electrostatic energy downhole, wherein such systems (of a second type) generally comprise the following: a wellbore originating at a geological surface, extending from said surface into a geological formation; a plurality of tubular segments disposed within the wellbore, wherein said tubular segments are useful in conveying hydrocarbon-based fluids out of said wellbore; at least one membrane-bearing tubular segment comprising: (i) an electrically-grounded outer upstream membrane electrode, (ii) an inner downstream membrane electrode, (iii) a dielectric filter membrane, comprising flow channels, disposed between the inner and outer membrane electrodes wherein at least a majority of said flow channels have an effective diameter of at least about 500 nm and at most about 200 ⁇ ; at least one device-bearing tubular segment comprising at least one device that can be usefully employed downhole; at least one electrical lead establishing connectivity between the
  • methods and/or systems of either a first or second type are further coupled with a wireless communication subsystem (or a step of wirelessly communicating) for wirelessly conveying, to the surface, data obtained by the devices being wirelessly powered by harnessed electrostatic energy, as described above.
  • FIG. 1 illustrates, in flow diagram form, methods of a first type for generating electrostatic energy downhole for the purpose of powering devices in a petroleum well, in accordance with some embodiments of the present invention
  • FIG. 2A depicts an electrically-isolated tubular segment of a system of a first type for generating electrostatic energy downhole for the purpose of powering devices in a petroleum well, in accordance with some embodiments of the present invention
  • FIG. 2B depicts how the electrically-isolated tubular segment shown in FIG. 2A can be integrated with a system of a first type, in accordance with some embodiments of the present invention
  • FIG. 3 illustrates, in flow diagram form, methods of a second type for generating electrostatic energy downhole for the purpose of powering devices in a petroleum well, in accordance with some embodiments of the present invention
  • FIG. 4A depicts a portion of a membrane-bearing tubular segment of a system of a second type for generating electrostatic energy downhole for the purpose of powering devices in a petroleum well, in accordance with some embodiments of the present invention.
  • FIG. 4B depicts how the membrane-bearing tubular segment shown in FIG. 4A can be integrated with a system of a second type, in accordance with some embodiments of the present invention.
  • the present invention is directed to processes (i.e., methods) for harnessing flow-induced electrostatic energy in an oil and/or gas well and utilizing this energy to power electrical devices downhole (i.e., in the wellbore).
  • the present invention is also directed to corresponding or otherwise associated systems through which such methods are implemented. Methods and systems will generally be characterized as being of either a first type or a second type, the details of which are described below.
  • the present invention is directed to one or more methods of powering devices in a petroleum well through the generation of electrostatic energy downhole, the petroleum well originating at a geological surface, having variable or non-variable orientation along the length of the well, and comprising a plurality of tubular segments disposed therewithin and connected in series along the well length, said method comprising the steps of: (Step 101) flowing a substantially non-conductive hydrocarbon-based fluid, as a flowstream, through a designated tubular length that is electrically-isolated from adjacent tubular segments to which it is connected (either in series or in parallel), wherein the non- conductive hydrocarbon-based fluid has a relative permittivity of between 2 and 40; (Step 102) generating a net, steady-state electrostatic potential between the flowstream and said designated tubular length; (Step 103) harvesting electrical energy from the electrostatic potential via a ground electrode (typically in the path of the flowstream) in electrical contact with the flowstream and an electrical lead
  • the petroleum well is operable for producing hydrocarbons (oil, gas, or combinations thereof) from the subsurface, and this production of hydrocarbons can take place on either land or offshore (incl. > 200 meters deep waters, referred to herein as "deepwater”).
  • hydrocarbons oil, gas, or combinations thereof
  • shore wells can be of a variety of types including, but not limited to, vertical and/or deviated wells, cased and/or open-hole wells, multilateral wells, and combinations of any or all of the foregoing.
  • the substantially non-conductive hydrocarbon-based fluid is a completion fluid, although drilling fluids, workover fluids, and produced fluids can be similarly utilized (vide infra).
  • Non-conductive hydrocarbon-based completion fluids are known in the art. By way of illustration and not limitation, examples of non-conductive hydrocarbon-based completion fluids can be found in Pasquier et al., United States Patent No. 7,858,564, issued Dec. 28, 2010; and Patel et al., United States Patent No. 5,189,012, issued on Feb. 23, 1993.
  • the substantially non-conductive hydrocarbon- based fluid is selected from the group consisting of (a) an injected fluid, (b) a produced fluid, and (c) combinations thereof.
  • examples of non-conductive hydrocarbon-based injection fluids can be found in Patton et al., United States Patent No. 3,301,327, issued Jan. 31, 1967. Produced fluids would naturally be the oil and/or gas being extracted from the reservoir, and perhaps comprising amounts of injection fluid (if such fluid was used). In enhanced oil recovery (EOR) operations, it is contemplated that electrostatic energy could be produced, and subsequently harnessed, during either or both of injection and production operations.
  • EOR enhanced oil recovery
  • the non-conductive hydrocarbon-based flowstream flows past the designated tubular length in a direction parallel to the path of the well.
  • flowstreams can be directed toward the surface or away from it, depending upon whether the flowstream comprises a produced fluid or an injection fluid.
  • EOR enhanced oil recovery
  • the flowstream can be cycled in both directions in the same well.
  • the non-conductive hydrocarbon-based flowstream flows past the designated tubular length in a side- pocket mandrel assembly providing for a diverted flowpath.
  • the diverted flow can be used to generate electrostatic energy, while not impeding flow (or offering only minimal fluid flow impedance) of fluids in the primary conduit through which they are transported. See Crawford et al., United States Patent No. 5,740,860, issued Apr. 21, 1998, for an example of how a side-pocket mandrel can be integrated with a production string.
  • the designated tubular length presents itself to the flowstream as a coating of a first type.
  • the coating of a first type is substantially non-conductive.
  • Exemplary such coating of a first type include, but are not limited to, material selected from the group consisting of polytetrafluoroethylene (PTFE), polyamides (Nylon), polyimides, polyvinylchloride (PVC), polyolefins, polyesters, and combinations thereof.
  • PTFE polytetrafluoroethylene
  • Nylon polyamides
  • PVC polyvinylchloride
  • Such coatings can be made with a range of uniformity and a variety of thicknesses, the latter often being dependent on the durability of the coating material and/or its "adhesiveness" to the tubular segment of which it is part.
  • Such coatings can also be multi-layered.
  • the designated tubular length comprises a rough-textured surface on at least a portion of its interior surface, wherein the rough-textured surface has an average roughness (R a ) of generally between about 100 nanometers (nm) and about 2.5 millimeters (mm), typically between about 5 micrometers ( ⁇ ) and about 1 mm, and more typically between about 5 ⁇ and about 250 ⁇ .
  • R a average roughness
  • Such rough-texturing of the interior surface can increase surface area and/or increase the fluid flow impedance— thereby enhancing the buildup of electrical charge.
  • the designated tubular length is electrically-isolated from adjacent tubular segments to which it is connected by means of a substantially- insulating coating of a second type about at least the regions that are in mechanical contact with the adjacent tubular segments.
  • the coating of a second type ca n be of the same or different from the coating of the first (vide supra), provided of course that it is electrically-insulating.
  • Such coatings of a second type can be continuous with that of the first type provided they are of the same material.
  • Exemplary such coating of a second type include, but are not limited to, material selected from the group consisting of polytetrafluoroethylene (PTFE), polyamides (Nylon), polyimides, polyvinylchloride (PVC), polyolefins, polyesters, and combinations thereof.
  • PTFE polytetrafluoroethylene
  • ylon polyamides
  • PVC polyvinylchloride
  • polyesters and combinations thereof.
  • the net, steady-state electrostatic potential is generally at least about 5 microvolts ( ⁇ ) and at most about 500 kilovolts (kV), typically at least about 0.5 millivolts (mV) to at most about 100 kV, and more typically at least about 2 mV to at most about 50 kV.
  • kV kilovolts
  • mV millivolts
  • the device deriving power from the harvested electrical energy is not particularly limited. Undoubtedly, it will have some utility downhole and be fabricated to withstand the environmental conditions to which it is exposed. Notwithstanding such aforementioned flexibility, in some embodiments the device deriving power from the harvested electrical energy is selected from the group consisting of one or more of the following: a pressure sensor, a temperature sensor, a sliding sleeve, a valve, telemetry electronics, flow meter, fluid sensing device, and combinations thereof. Additionally or alternatively, in some embodiments, the device draws power from an electrical storage device (e.g., one or more batteries and/or a capacitor or bank thereof) that is, in turn, charged by the harvested electrical energy.
  • an electrical storage device e.g., one or more batteries and/or a capacitor or bank thereof
  • the substantially non-conductive hydrocarbon-based fluid is synthetically-derived and/or comprises at least one synthetically-derived component.
  • examples of potentially-suitable such synthetically-derived, substantially non-conductive hydrocarbon-based fluids can be found in Van Slyke, United States Patent No. 6,034,037, issued Mar. 7, 2000.
  • the electrostatic potential is generated at least about 100 meters below the well surface (for offshore wells this would be the sea floor). Regardless of where in the well the energy is created and harvested, it can be utilized to power devices that are up to hundreds of meters above/below or fore/aft the location at which it is harnessed— using electrical leads of sufficient length and durability.
  • the present invention is directed toward one or more systems of a first type, such systems 200 being operable for powering devices in a petroleum well through the generation of electrostatic energy downhole and generally comprising: a wellbore 202 originating at a geological surface 201 and extending from said surface into a geological formation 203; a plurality of tubular segments (e.g., 204, 205, 209) disposed within the wellbore, wherein said tubular segments are useful in conveying hydrocarbon-based fluids out of said wellbore; at least one electrically-isolated tubular segment 204 that is electrically isolated from any adjoining segments (via insulation 207), wherein said electrically- isolated tubular segment includes a high friction surface 214 on its interior; at least one device-bearing tubular segment 209 comprising at least one device that can be usefully employed downhole (and generally requiring power to operate); at least one electrical lead 206 establishing connectivity between the at least
  • such above-described plurality of tubular segments 204, 205, and 209 can range in length from less than about 1 meter to well over 1000 meters. In some such embodiments, the length of the segments coincides with the length of tubing joints and/or subs. In some or other embodiments, such segments comprise a plurality of such joints and/or subs.
  • the petroleum well 202 is operable for producing oil, gas, or combinations thereof.
  • the well can be either on land or offshore (incl. deepwater), and can be of the substantially vertical type, horizontal type or otherwise deviated, or combinations thereof.
  • the petroleum well is a multilateral well.
  • the well is a cyclic injection and recovery well (i.e., a "huff-n-puff"). See, e.g., Wehner, United States Patent No. 5,381,863, issued Jan. 17, 1995.
  • the electrically-isolated tubular segment 204 exposes or otherwise presents itself to the flowstream (flow 217) as a substantially non-conductive coating comprised of a material selected from the group consisting of polytetrafluoroethylene (PTFE), polyamides (Nylon), polyimides, polyvinylchloride (PVC), polyolefins, polyesters, combinations thereof, and non- conductive polymer compositions generally— particularly those that lend themselves well to coatings.
  • PTFE polytetrafluoroethylene
  • Nylon polyamides
  • PVC polyvinylchloride
  • polyolefins polyolefins
  • polyesters combinations thereof
  • non- conductive polymer compositions generally— particularly those that lend themselves well to coatings.
  • non- conductive polymer compositions generally— particularly those that lend themselves well to coatings.
  • such coatings can have a range of thicknesses and uniformities, and they can be multi- layered.
  • the coatings can additionally or alternatively be ceramic and/or metallic in
  • the electrically-isolated tubular segment 204 comprises a high friction surface having an average roughness (R a ) of generally between about 100 nm and about 2.5 mm, typically between about 5 ⁇ and about 1 mm, and more typically between about 5 ⁇ and about 250 ⁇ .
  • R a average roughness
  • Such high friction (i.e., rough-textured) interior surface(s) can increase surface area and/or increase the fluid flow impedance (via increased friction)— thereby enhancing the buildup of electrical charge.
  • the at least one device- bearing tubular segment 209 comprises one or more devices selected from the group consisting of pressure sensors, temperature sensors, sliding sleeves, valves, telemetry electronics, flow meters, fluid sensing devices, and combinations thereof.
  • devices are those that require power, and which would normally obtain that power via batteries or encapsulated cable from the surface of the well.
  • the powered device(s) being integral with, or otherwise part of, the at least one device-bearing tubular segment 209 is in close proximity to the electrically-isolated tubular segment 204, this need not always be the case.
  • the at least one electrical lead can span a distance within the wellbore of generally up to about 1000 meters, but typically no more than about 200 meters, and more typically no more than about 50 meters.
  • the flow of substantially non- conductive hydrocarbon-based fluid 217 comprises a fluid selected from the group consisting of heptanes, diesel, crude oil, mineral oil, and combinations thereof; such fluids, however, are merely exemplary.
  • additional examples of non-conductive hydrocarbon-based (completion fluids in this case) can be found in Pasquier et al., United States Patent No. 7,858,564, issued Dec. 28, 2010; and Patel et al., United States Patent No. 5,189,012, issued on Feb. 23, 1993.
  • the flow of substantially non- conductive hydrocarbon-based fluid possesses a flow rate of generally between about 1 liter/minute and about 55,000 liters/minute, typically between about 1 liter/minute and about 10,000 liters/min, and more typically between about 10 liters/minute and about 5,000 liters/minute.
  • the flow rate is generally seen to be proportional to the electric potential that develops between the flow 217 and the at least one electrically-isolated tubular segment 204. Accordingly, it is contemplated that the electric potential could be altered to a desired value by deliberately changing the flow rate. From an operational perspective, flow rate would need to be sufficient for generating a usable electrostatic potential.
  • flow 217 is characterized as being turbulent. While not intending to be bound by theory, turbulent flow may be preferred for inducing electrostatic potentials in at least some method and system embodiments of the present invention, and perhaps particularly so for such methods and systems of a first type. See, e.g., Abedian et al., "Theory for Electric Charging in Turbulent Pipe Flow," Journal of Fluid Mechanics, vol. 120, pp. 199-217, 1982; and Abedian et al., “Electric Currents Generated by Turbulent Flows of Liquid Hydrocarbons in Smooth Pipes: Experiment vs. Theory," Chemical Engineering Science, vol. 41(12), pp. 3183- 3189, 1986.
  • such above-described systems further comprise a telemetry subsystem or means (not shown in FIGS. 2A and 2B) operable for conveying device-generated data to the surface. While not limited thereto, such systems are preferably wireless, with such wireless subsystems being more fully described in Section 6 below. 4. Methods of a Second Type
  • Method embodiments of a second type share significant commonality with method embodiments of a first type.
  • the primary manner in which they differ is in how the electrostatic potential is generated: methods of a second type involve passing a substantially non-conductive hydrocarbon-based fluid through a membrane.
  • Other aspects and/or variables of these two types of methods (and their corresponding systems) are largely the same for each.
  • the present invention is directed to methods (of a second type) of powering devices in a petroleum well through the generation of electrostatic energy downhole, the petroleum well originating at a geological surface and being operable for the production of oil, natural gas, or mixtures thereof, said methods generally comprising the steps of: (Step 301) flowing a substantially non-conductive hydrocarbon- based fluid, as a flowstream, through a substantially insulating membrane; (Step 302) generating a net, steady-state electrostatic potential between the flowstream and said membrane, wherein the membrane comprises a plurality of flow channels through which the substantially non-conductive hydrocarbon-based fluid can pass, and wherein at least a majority of said flow channels have an effective diameter of at least about 500 nm and at most about 200 ⁇ ; (Step 303) harvesting electrica l energy from the electrostatic potential via a ground electrode in electrical contact with the flowstream and an electrical lead in electrical contact with the membrane; and (Step 304)
  • the substantially non-conductive hydrocarbon- based fluid is selected from the group consisting of (a) completion fluid, (b) displacement fluid, (c) drilling fluid, and (d) combinations thereof.
  • Non-conductive hydrocarbon-based types of such fluids are known in the art.
  • exemplary such fluids can be those used for methods of a first type (vide supra).
  • the substantially insulating membrane is comprised of a material that is sufficiently insulating from an operational standpoint.
  • average pore size of the membrane is generally between about 50 nm and about 50 mm, typically between about 100 nm and about 1 mm, and more typically between about 250 nm and about 250 ⁇ .
  • the substantially insulating membrane is comprised of a material selected from the group consisting of polytetrafluoroethylene (PTFE), polyamides (Nylon), polyimides, polyvinylchloride (PVC), polyolefins, polyesters, and combinations thereof.
  • PTFE polytetrafluoroethylene
  • nylon polyamides
  • PVC polyvinylchloride
  • polyesters and combinations thereof.
  • the downstream electrode generally is made of a material sufficiently conductive (and durable) for it to serve as an electrode in the manner described above. Accordingly, the material of which it is comprised is not particularly limited. In some such embodiments, the downstream electrode is substantially porous so as to permit flow of fluid therethrough. In some such embodiments, average pore size of the downstream electrode is generally between about 1 ⁇ and about 10 cm, typically between about 1 ⁇ and about 5 cm, and more typically between about 5 ⁇ and about 5 cm.
  • the upstream electrode is generally made of a material sufficiently conductive and durable for it to serve as an electrode in the manner described above. Accordingly, the material of which it is comprised is not particularly limited. In some such embodiments, the upstream electrode is substantially porous so as to permit flow of fluid therethrough. In some such embodiments, average pore size of the upstream (ground) electrode is generally between about 1 ⁇ and about 10 cm, typically between about 1 ⁇ and about 5 cm, and more typically between about 5 ⁇ and about 5 cm.
  • the upsteam electrode takes the form of a conductive mesh
  • the conductive mesh is generally of a mesh size that corresponds to grids between about lxl ⁇ and about 10x10 cm, typically between about 5x5 ⁇ and about 10x10 cm, and more typically between about 5x5 ⁇ and about 5x5 cm.
  • the material of which the mesh is made is not particularly limited, except that it should possess sufficient electrical conductivity, and be sufficiently robust, so as to be durably operational in the wellbore environment in which it is placed.
  • the at least one membrane- bearing tubular segment comprises, in whole or in part, a sand control device or means.
  • Sand control devices like sand screens are known in the art and are ubiquitously deployed in wells throughout the world. Care must be taken in selection of such devices or screens so that the material makeup and dimensional attributes of the componentry are consistent with those of the membrane-bearing tubular segment describe above.
  • the at least one membrane-bearing tubular segment can be constructed so as to also provide for utility as a sand control device.
  • the net, steady-state electrostatic potential is generally at least about 5 ⁇ and at most about 500 kV, typically at least about 0.5 mV to at most about 100 kV, and more typically at least about 2 mV to at most about 50 kV.
  • a potential should be sufficiently great so as to operationally-power a device downhole— even if such powering is by way of an electrical device.
  • the device draws power from an electrical storage device that is, in turn, charged by the harvested electrical energy.
  • the device deriving power from the harvested electrical energy is selected from the group consisting of one or more of the following: a pressure sensor, a temperature sensor, a sliding sleeve, a valve, telemetry electronics, flow meter, fluid sensing device, and combinations thereof.
  • Systems of a second type are generally consistent with implementing one or more methods (of a second type) as described above via a functional infrastructure, and as described in the passages which follow. Additionally, system embodiments of a second type share significant commonality with system (and method) embodiments of a first type. The primary manner in which they differ is in how the electrostatic potential is generated: systems of a second type involve passing a substantially non-conductive hydrocarbon-based fluid through a membrane assembly in a membrane-bearing tubular segment (vide infra). Other aspects and/or variables of these two types of systems (and their corresponding methods) are largely the same for each.
  • such systems for powering devices in a petroleum well through the generation of electrostatic energy downhole, generally comprise (as system 400) the following: a wellbore 402 originating at a geological surface 401, extending from said surface into a geological formation 403; a plurality of tubular segments (e.g., 404, 405, 409) disposed within the wellbore, wherein said tubular segments are useful in conveying hydrocarbon-based fluids out of said wellbore; at least one membrane-bearing tubular segment 404 comprising: (i) an electrically-grounded outer upstream membrane electrode 410, (ii) an inner downstream membrane electrode 412, (iii) a dielectric filter membrane 411, comprising flow channels, disposed between the inner and outer membrane electrodes wherein at least a majority of said flow channels have an effective diameter of at least about 500 nm and at most about 200 ⁇ ; at least one device-bearing tubular
  • the petroleum well is operable for producing oil, gas, or combinations thereof.
  • the petroleum well is a multilateral well.
  • the well can be either on land or offshore (incl. deepwater), and can of the substantially vertical type, horizontal type or otherwise deviated, or combinations thereof.
  • the petroleum well is a multilateral well.
  • the well is a cyclic injection and recovery well (i.e., a "huff-n-puff"). See, e.g., Wehner, United States Patent No. 5,381,863, issued Jan. 17, 1995.
  • the at least one device-bearing tubular segment 409 comprises one or more devices selected from the group consisting of pressure sensors, temperature sensors, valves, telemetry electronics, flow meters, fluid sensing devices, and combinations thereof.
  • the membrane-bearing tubular segment 404 varies in length generally from at least about 10 cm to at most about 2500 m, typically from at least about 10 cm to at most about 1000 m, and more typically from at least about 25 cm to at most about 1000 m.
  • each of the electrically-grounded outer upstream membrane electrode 410, the inner downstream membrane electrode 412, and the dielectric filter membrane 411 are of substantially the same length.
  • the dielectric filter membrane 411 is comprised of a material selected from the group consisting of polytetrafluoroethylene (PTFE), polyamides (Nylon), polyimides, polyvinylchloride (PVC), polyolefins, polyesters, and combinations thereof.
  • PTFE polytetrafluoroethylene
  • nylon polyamides
  • PVC polyvinylchloride
  • polyesters and combinations thereof.
  • one or more of the electrically- grounded outer upstream membrane electrode 410, the inner downstream membrane electrode, and the dielectric filter membrane can additionally be used for purposes other than generating power (e.g., as a sand control device).
  • the at least one electrical lead 406 can span a distance within the wellbore of generally from at least about 1 mm to at most about 10,000 m (there is generally an upper limit that is roughly equal to the length of the well), typically from at least about 1 cm to at most about 5,000 m, and more typically from at least about 1 cm to at most about 1,000 m.
  • the flow of substantially non- conductive hydrocarbon-based fluid 402 comprises a fluid selected from the group consisting of heptanes, diesel, crude oil, mineral oil, combinations thereof, and the like.
  • exemplary such fluids can be those used for methods and systems of a first type (vide supra).
  • the flow of substantially non- conductive hydrocarbon-based fluid 402 possesses a flow rate of generally between about 1 liter/minute and about 55,000 liters/minute, typically between about 1 liter/minute and about 10,000 liters/min, and more typically between about 10 liters/minute and about 5,000 liters/minute.
  • electrical potential is harnessed by first charging an electrical storage device (e.g., a battery or capacitor), and then using said electrical storage device to power the at least one device in the at least one device-bearing tubular segment.
  • an electrical storage device e.g., a battery or capacitor
  • the system further comprises a telemetry subsystem operable for conveying device-generated data to the surface. While wireless telemetry techniques are preferred, cabled means of communicating data are also contemplated. Additionally or alternatively, in some embodiments recording devices are employed for batch analysis at some later time, wherein the recording devices are removed from the well and analyzed. I n some embodiments, the telemetry subsystem and/or the recording device(s) is at least partially powered by means of electrostatic energy generated in the downhole environment.
  • the methods and systems described above optionally utilize a telemetry means or subsystem to convey data (obtained in the wellbore) to the surface. While data can be recorded and later brought to the surface for analysis, the conveyance of such data is more often preferably wireless in nature. Such conveyance of data can also be via cabled transmission lines, but such cabled means generally result in the loss of any advantages the wireless powered methods/systems afford. Regardless, real-time data accessibility (whether wireless or cabled) is generally preferable to batch recording and analysis because it permits on-the-fly adaptability.
  • wireless transmission of data can be at least partially provided by mud-based telemetry methods and/or acoustic transmissions.
  • mud-based telemetry methods See, e.g., Kotlyar, U.S. Patent No. 4,771,408, issued Sept. 13, 1988; and Beattie et al., U.S. Patent No. 6,421,298, issued Jul. 16, 2002.
  • wireless transmission of data (and power) up and/or down a well using acoustic transmissions see, e.g., Klatt, U.S. Patent No. 4,215,426, issued Jul. 29, 1980; and Drumbeller, U.S. Patent No. 5,222,049, issued Jun. 22, 1993.
  • electromagnetic (EM) transmissions of a type described in, for example, Briles et al., U.S. Patent No. 6,766,141, issued Jul. 20, 2004, are used to transmit data and/or power into and out of the cased wellbore.
  • the downhole resonant circuits used in such methods and systems can be integrated directly or indirectly with the one or fluid property analyzers, so as to convey information into, and out of, the well. See also, e.g., Coates et al., U.S. Patent No. 7,636,052, issued Dec. 22, 2009; Thompson et al., U.S. Patent No. 7,530,737, issued May 12, 2009; Coates et al., U.S. Patent Appl. Pub.
  • the present invention is directed to methods for harnessing flow-induced electrostatic energy in an oil and/or gas well and using this energy to power electrical devices (e.g., flowmeters, electrically-actuated valves, etc.) downhole.
  • electrical devices e.g., flowmeters, electrically-actuated valves, etc.
  • the present invention is also directed to corresponding systems through which such methods are implemented.

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)
  • Mechanical Engineering (AREA)
  • Geophysics (AREA)
  • Electromagnetism (AREA)
  • Chemical & Material Sciences (AREA)
  • Dispersion Chemistry (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
  • Testing Relating To Insulation (AREA)
  • Transformer Cooling (AREA)
  • Electrostatic Separation (AREA)

Abstract

La présente invention concerne des procédés (méthodes) de captage d'énergie électrostatique induite par l'écoulement dans un forage pétrolier et/ou gazier et l'utilisation de cette énergie pour alimenter des dispositifs électriques (par ex. débitmètres, vannes à commande électrique, etc.) en fond de puits.
PCT/US2012/031432 2011-04-27 2012-03-30 Générateur d'énergie électrostatique induite par l'écoulement destiné à être utilisé en fond de puits dans les forages pétroliers et gaziers WO2012148628A2 (fr)

Priority Applications (4)

Application Number Priority Date Filing Date Title
EP12776615.2A EP2702241A4 (fr) 2011-04-27 2012-03-30 Générateur d'énergie électrostatique induite par l'écoulement destiné à être utilisé en fond de puits dans les forages pétroliers et gaziers
BR112013027083A BR112013027083A2 (pt) 2011-04-27 2012-03-30 gerador de energia eletrostática induzida por fluxo para uso em fundo de poço em poços de petróleo e gás
CA2833243A CA2833243A1 (fr) 2011-04-27 2012-03-30 Generateur d'energie electrostatique induite par l'ecoulement destine a etre utilise en fond de puits dans les forages petroliers et gaziers
AU2012250159A AU2012250159A1 (en) 2011-04-27 2012-03-30 Flow-induced electrostatic power generator for downhole use in oil and gas wells

Applications Claiming Priority (4)

Application Number Priority Date Filing Date Title
US13/094,964 US8511373B2 (en) 2011-04-27 2011-04-27 Flow-induced electrostatic power generator for downhole use in oil and gas wells
US13/094,954 US8714239B2 (en) 2011-04-27 2011-04-27 Flow-induced electrostatic power generator for downhole use in oil and gas wells
US13/094,964 2011-04-27
US13/094,954 2011-04-27

Publications (2)

Publication Number Publication Date
WO2012148628A2 true WO2012148628A2 (fr) 2012-11-01
WO2012148628A3 WO2012148628A3 (fr) 2012-12-27

Family

ID=47072990

Family Applications (1)

Application Number Title Priority Date Filing Date
PCT/US2012/031432 WO2012148628A2 (fr) 2011-04-27 2012-03-30 Générateur d'énergie électrostatique induite par l'écoulement destiné à être utilisé en fond de puits dans les forages pétroliers et gaziers

Country Status (5)

Country Link
EP (1) EP2702241A4 (fr)
AU (1) AU2012250159A1 (fr)
BR (1) BR112013027083A2 (fr)
CA (1) CA2833243A1 (fr)
WO (1) WO2012148628A2 (fr)

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013165783A1 (fr) * 2012-04-30 2013-11-07 Chevron U.S.A. Inc. Appareil de détection d'écoulement et procédés destinés à être utilisés dans des puits de pétrole et de gaz

Families Citing this family (2)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
CN110242276A (zh) * 2019-05-29 2019-09-17 中国地质大学（武汉） 一种基于摩擦纳米发电的井下气泡截面含气率测量传感器
CN112145548B (zh) * 2020-08-31 2021-12-28 清华大学 自供能滚动轴承、轴承组件和旋转机械

Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20080061789A1 (en) 2006-09-08 2008-03-13 Chevron U.S.A. Inc. Telemetry apparatus and method for monitoring a borehole

Family Cites Families (7)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US4223241A (en) * 1978-08-28 1980-09-16 The United States Of America As Represented By The Secretary Of The Navy Electrostatic charge generator
US4494009A (en) * 1983-09-19 1985-01-15 Tex Yukl Method and apparatus for capturing an electrical potential generated by a moving air mass
US5839508A (en) * 1995-02-09 1998-11-24 Baker Hughes Incorporated Downhole apparatus for generating electrical power in a well
US6440600B1 (en) * 1997-05-08 2002-08-27 Michael E. Starzak Apparatus and method for generating electrical power from fluid flow through charged pores
NO319947B1 (no) * 2000-09-05 2005-10-03 Schlumberger Holdings Mikrosvitsjer for nedhulls-anvendelse
AR045237A1 (es) * 2004-08-09 2005-10-19 Servicios Especiales San Anton Generador de energia electrica que usa las vibraciones provocadas por una herramienta de perforacion
EP1856789B1 (fr) * 2005-02-08 2018-08-15 Welldynamics, Inc. Generateur de puissance electrique en fond de trou

Patent Citations (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20080061789A1 (en) 2006-09-08 2008-03-13 Chevron U.S.A. Inc. Telemetry apparatus and method for monitoring a borehole

Non-Patent Citations (1)

* Cited by examiner, † Cited by third party
Title
See also references of EP2702241A4

Cited By (1)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
WO2013165783A1 (fr) * 2012-04-30 2013-11-07 Chevron U.S.A. Inc. Appareil de détection d'écoulement et procédés destinés à être utilisés dans des puits de pétrole et de gaz

Also Published As

Publication number Publication date
AU2012250159A1 (en) 2013-11-07
EP2702241A2 (fr) 2014-03-05
EP2702241A4 (fr) 2015-09-16
BR112013027083A2 (pt) 2016-12-27
WO2012148628A3 (fr) 2012-12-27
CA2833243A1 (fr) 2012-11-01

Similar Documents

Publication Publication Date Title
US8511373B2 (en) Flow-induced electrostatic power generator for downhole use in oil and gas wells
US8714239B2 (en) Flow-induced electrostatic power generator for downhole use in oil and gas wells
US9685890B2 (en) Flow induced electrostatic power generator for tubular segments
US8988178B2 (en) Downhole inductive coupler assemblies
US6840316B2 (en) Tracker injection in a production well
US7775275B2 (en) Providing a string having an electric pump and an inductive coupler
US8330617B2 (en) Wireless power and telemetry transmission between connections of well completions
US9683441B2 (en) Power supply for wired pipe with rechargeable energy storage
US20110210645A1 (en) Downhole static power generator
US10648303B2 (en) Wireline-deployed solid state pump for removing fluids from a subterranean well
US20160265315A1 (en) Transverse flow downhole power generator
US20030066652A1 (en) Wireless downhole well interval inflow and injection control
US10480501B2 (en) Nested bellows pump and hybrid downhole pumping system employing same
AU2001243391A1 (en) Tracer injection in a production well
WO2001065053A1 (fr) Injection de traceur dans un puits de production
US10934785B2 (en) Downhole wet connection systems
US20100314106A1 (en) Low cost rigless intervention and production system
WO2012148628A2 (fr) Générateur d'énergie électrostatique induite par l'écoulement destiné à être utilisé en fond de puits dans les forages pétroliers et gaziers
US9068431B2 (en) Flow sensing apparatus and methods for use in oil and gas wells
US9556712B2 (en) Flow induced electrostatic power generator for tubular segments

Legal Events

Date Code Title Description
121 Ep: the epo has been informed by wipo that ep was designated in this application

Ref document number: 12776615

Country of ref document: EP

Kind code of ref document: A2

ENP Entry into the national phase in:

Ref document number: 2833243

Country of ref document: CA

WWE Wipo information: entry into national phase

Ref document number: 2012776615

Country of ref document: EP

NENP Non-entry into the national phase in:

Ref country code: DE

ENP Entry into the national phase in:

Ref document number: 2012250159

Country of ref document: AU

Date of ref document: 20120330

Kind code of ref document: A

REG Reference to national code

Ref country code: BR

Ref legal event code: B01A

Ref document number: 112013027083

Country of ref document: BR

ENP Entry into the national phase in:

Ref document number: 112013027083

Country of ref document: BR

Kind code of ref document: A2

Effective date: 20131021