WO2017087348A1 - Procédés et systèmes de détermination d'une fermeture de fracture souterraine - Google Patents

Procédés et systèmes de détermination d'une fermeture de fracture souterraine Download PDF

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Publication number
WO2017087348A1
WO2017087348A1 PCT/US2016/061946 US2016061946W WO2017087348A1 WO 2017087348 A1 WO2017087348 A1 WO 2017087348A1 US 2016061946 W US2016061946 W US 2016061946W WO 2017087348 A1 WO2017087348 A1 WO 2017087348A1
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WO
WIPO (PCT)
Prior art keywords
fracture
proppant
electrically conductive
electric
earth
Prior art date
Application number
PCT/US2016/061946
Other languages
English (en)
Inventor
Chad Cannan
Lewis BARTEL
Terry PALISCH
David Aldridge
Todd Roper
Steve Savoy
Daniel R. Mitchell
Original Assignee
Carbo Ceramics, Inc.
Sandia Corporation
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 US14/942,304 external-priority patent/US10267134B2/en
Application filed by Carbo Ceramics, Inc., Sandia Corporation filed Critical Carbo Ceramics, Inc.
Priority to EA201891194A priority Critical patent/EA201891194A1/ru
Priority to CN201680078520.1A priority patent/CN108474248A/zh
Publication of WO2017087348A1 publication Critical patent/WO2017087348A1/fr

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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/80—Compositions for reinforcing fractures, e.g. compositions of proppants used to keep the fractures open
    • 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
    • E21B43/25—Methods for stimulating production
    • E21B43/26—Methods for stimulating production by forming crevices or fractures
    • E21B43/267—Methods for stimulating production by forming crevices or fractures reinforcing fractures by propping
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/20—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with propagation of electric current

Definitions

  • Embodiments of the present invention relate generally to hydraulic fracturing of geological formations, and more particularly to electrically conductive proppants used in the hydraulic fracture stimulation of gas, oil, or geothermal reservoirs. Embodiments of the present invention relate to methods and systems utilizing the electrically conductive proppants.
  • frac operations In order to stimulate and more effectively produce hydrocarbons from downhole formations, especially formations with low porosity and/or low permeability, induced fracturing (called “frac operations”, “hydraulic fracturing”, or simply “fracing") of the hydrocarbon-bearing formations has been a commonly used technique.
  • frac operations induced fracturing
  • hydrocarbon fracturing hydrocarbon-bearing formations
  • the high pressure fluids exit the borehole via perforations through the casing and surrounding cement, and cause the formations to fracture, usually in thin, generally vertical sheet-like fractures in the deeper formations in which oil and gas are commonly found.
  • fractures usually in thin, generally vertical sheet-like fractures in the deeper formations in which oil and gas are commonly found.
  • These induced fractures generally extend laterally a considerable distance out from the wellbore into the surrounding formations, and extend vertically until the fracture reaches a formation that is not easily fractured above and/or below the desired frac interval.
  • the fluid sometimes called slurry
  • pumped downhole does not contain solids that remain lodged in the fracture when the fluid pressure is relaxed, then the fracture re-closes, and most of the permeability conduit gain is lost.
  • proppants are generally composed of sand grains or ceramic particles that are placed in the induced fractures to keep them from fully re-closing. After the slum ' is pumped downhole and the fluid pressure is released, the formation walls close on the propping agent creating a "propped fracture" which oftentimes provides a high conductivity channel in the subterranean formation. The time for fractures to close is formation dependent and is so far unable to be directly measured.
  • FIG. 1 is a diagram of the geometric layout of a vertical or deviated well in which layers of the earth having varying electrical and mechanical properties are depicted.
  • FIG. 2 is a schematic of an installed horizontal wellbore casing string traversing a hydrocarbon bearing zone with proppant filled fractures in which layers of the earth having varying electrical and mechanical properties are depicted.
  • FIG. 3 is a schematic cross-sectional illustration off a hydraulic fracture mapping system which depicts two embodiments for introducing electric current into a wellbore, namely energizing the wellbore at the surface or energizing via a wireline with a sinker bar near the perforations in the wellbore.
  • FIG. 4 is a schematic plan illustration of a hydraulic fracture mapping system.
  • FIG. 5 is a schematic perspective illustration of a hydraulic fracture mapping system.
  • FIG. 6A is a schematic illustration of an electrically insulated casing joint.
  • FIG. 6B is a schematic illustration of an electrically insulated casing collar.
  • FIG. 7 A is a schematic cross-sectional illustration off a proppant filled hydraulic fracture before closure.
  • FIG. 7B is a schematic cross-sectional illustration off a proppant filled hydraulic fracture after closure.
  • FIG. 8 is schematic illustration of a test system for measuring proppant electrical resistance.
  • FIG. 9 is a graph of Conductivity (Siemens/m) vs. Pressure (psi) for CARBOLITE 20/40 coated with nickel and CARBOLITE 20/40 coated with copper.
  • FIG. 10 is a graph of Conductivity (Siemens/m) vs. Pressure (psi) for CARBOLITE 20/40 coated with varied thickness of nickel.
  • FIG. 11 shows a profile of a simulation of voltage measured between a pair of simulated electric field sensors along a line that is over the horizontal section of a well track.
  • Described herein are methods for determining fracture closure.
  • methods for determining a closure time of a fracture by electrically energizing a proppant pack of electrically conductive sintered, substantially round and spherical particles in the fracture.
  • electromagnetic methods that include electrically energizing the earth at or near a fracture at depth and measuring the electric and magnetic responses at the earth's surface or in adjacent wells/boreholes at a series of time intervals.
  • the electrically conductive sintered, substantially round and spherical particles can be detectable by electromagnetic (EM) methods.
  • the electrically conductive proppant can include one or more coatings of electrically conductive material on its outer surfaces.
  • substantially round and spherical and related forms, as used herein, is defined to mean an average ratio of minimum diameter to maximum diameter of about 0.8 or greater, or having an average sphericity value of about 0.8 or greater compared to a Krumbein and Sloss chart.
  • the electromagnetic methods described herein can include energizing the earth in the fractured well/borehole or in a well/borehole adjacent to the fractured well/borehole.
  • the electromagnetic methods described herein can be used in connection with a cased wellbore, such as well 20 shown in FIG. 1, or in an uncased wellbore (not shown).
  • casing 22 extends within well 20 and well 20 extends through geological strata 24a-24i in a manner that has three dimensional components.
  • FIG. 2 a partial cutaway view is shown with production well 20 extending vertically downward through one or more geological layers 24a-24i and horizontally in layer 24i. While wells are conventionally vertical, the electromagnetic methods described herein are not limited to use with vertical wells. Thus, the terms “vertical” and “horizontal” are used in a general sense in their reference to wells of various orientations.
  • the preparation of production well 20 for hydraulic fracturing can include drilling a bore 26 to a desired depth and then in some cases extending the bore 26 horizontally so that the bore 26 has any desired degree of vertical and horizontal components.
  • a casing 22 can be cemented 28 into well 20 to seal the bore 26 from the geological layers 24a-24i in FIG. 2.
  • the casing 22 can have a plurality of perforations 30 and/or sliding sleeves (not shown). The perforations 30 are shown in FIG.
  • the perforations can be located at any desired depth or horizontal distance along the bore 26, but are typically at the location of a hydrocarbon bearing zone in the geological layers 24, which may be within one or more of the geological layers 24a-24j .
  • the well 20 can include no casing, such as in the case of an open-hole well.
  • the hydrocarbon bearing zone may contain oil and/or gas, as well as other fluids and materials that have fluid- like properties.
  • the hydrocarbon bearing zone in geological layers 24a-24j is hydraulically fractured by pumping a fluid into casing 22 and through perforations 30 at sufficient rates and pressures to create fractures 32 and then incorporating into the fluid an electrically conductive proppant which will prop open the created fractures 32 when the hydraulic pressure used to create the fractures 32 is released.
  • hydraulic fractures 32 shown in FIG. 2 are oriented radially away from the metallic well casing 22. This orientation is exemplary in nature. In practice, hydraulically- induced fractures 32 may be oriented radially as in FIG. 2, laterally or intermediate between the two. Various orientations are exemplary and not intended to restrict or limit the electromagnetic methods described herein in any way.
  • the electrically conductive proppant can be introduced into one or more subterranean fractures during any suitable hydraulic fracturing operation to provide an electrically conductive proppant pack.
  • any combination of the electrically conductive proppant and a non-electrically conductive proppant can be introduced into one or more fractures to provide an electrically conductive proppant pack.
  • the electrically conductive proppant of the electrically conductive proppant pack can include a non-uniform coating of electrically conductive material and/or a substantially uniform coating of electrically conductive material.
  • electric current is carried down wellbore 20 to an energizing point which will generally be located within 10 meters or more (above or below) of perforations 30 in casing 22 via a seven strand wire line insulated cable 34, such as those which are well known to those of ordinary skill in the art and are widely commercially available from Camesa Wire, Rochester Wire and Cable, Inc., WireLine Works, Novametal Group, and Quality Wireline & Cable Inc.
  • the wire line insulated cable 34 can contain 1 to 6 strands or 8 or more strands.
  • a sinker bar 36 connected to the wire line cable 34 contacts or is in close proximity to the well casing 22 whereupon the well casing 22 becomes a current line source that produces subsurface electric and magnetic fields.
  • the wire line cable 34 can be connected to or otherwise attached to a centralizer and/or any other suitable downhole tool in addition to or in lieu of the sinker bar 26. These fields interact with the fracture 32 containing electrically conductive proppant to produce secondary electric and magnetic fields that can be used to detect closure and closure time of the proppant-filled fracture 32.
  • a power control box 40 is connected to casing 22 by a cable 42 to provide an electric current return for current injected via the sinker bar 36. Another embodiment is to connect the power control box 40 directly to the earth via cable 54. Another embodiment is to inject a current into the fracture well 20 by directly energizing the casing 22 at the well head or any other suitable surface location with the current return cable 54 connected to the earth.
  • the power control box 40 is connected wirelessly by a receiver/transmitter 43 to a receiver/transmitter 39 on equipment truck 41.
  • the electric current source may be configured to generate input current waveforms of various types (i.e., pulses, continuous wave, or repeating or periodic waveforms or pseudo random binary pulse) that generate input electromagnetic field waveforms having a corresponding amplitude and corresponding temporal characteristics to the input current waveform. Accordingly, the conductive casing can be electrically energized and act as a spatially-extended source of electric current.
  • various types i.e., pulses, continuous wave, or repeating or periodic waveforms or pseudo random binary pulse
  • Electromagnetic fields generated by the current in the well casing 22 and that propagate to various locations in a volume of Earth can be altered by the presence of the proppant following the injection of the proppant into the fracture 32. Electromagnetic fields generated by the currents in both the well casing and the proppant propagate to various locations in a three-dimensional volume of Earth and are sensed using sensors.
  • a plurality of electric and magnetic field sensors 38 will be located on the earth's surface in a rectangular or other suitable array covering the area around the fracture well 20 and above the anticipated fracture 32.
  • the sensors 38 are connected wirelessly to a receiver/transmitter 39 on equipment truck 41.
  • the maximum dimension of the array (aperture) in general should be at least 80 percent of the depth to the fracture zone.
  • Sensor locations can be optimized for detecting the proppant filled fracture 32 using numerical simulations.
  • the sensors 38 will measure the x, y and z component responses of the electric and magnetic fields.
  • the responses of the electric and magnetic field components will depend upon: the orientation of the fracture well 20, the orientation of the fracture 32, the electrical conductivity, magnetic permeability, and electric permittivity of layers 24a-24j, the electrical conductivity, magnetic permeability, and electric permittivity of the proppant filled fracture 32, and the volume of the proppant filled fracture 32.
  • the electrical conductivity, magnetic permeability and electric permittivity of the geological layers residing between the surface and the target formation layers 24a-24j influence the recorded responses. From the field-recorded responses, details of the proppant filled fracture 32, such as location and closure, can be determined.
  • electric and magnetic sensors may be located in adjacent well/boreholes.
  • the current may or may not be uniform as the current flows back to the surface along the well casing 22.
  • current leakage occurs along wellbore 20 such as along path 50 or 52 and returns to the electrical ground 54 which is established at the well head.
  • the well casing is represented as a leaky transmission line in data analysis and numerical modeling.
  • an insulating joint may be installed by coating the mating surfaces 60 and 62 of the joint with a material 64 having a high dielectric strength, such as any one of the well-known and commercially available plastic or resin materials which have a high dielectric strength and which are of a tough and flexible character adapted to adhere to the joint surfaces so as to remain in place between the joint surfaces.
  • a material 64 having a high dielectric strength such as any one of the well-known and commercially available plastic or resin materials which have a high dielectric strength and which are of a tough and flexible character adapted to adhere to the joint surfaces so as to remain in place between the joint surfaces.
  • plastic or resin materials include epoxies, phenolics, rubber compositions, and alkyds, and various combinations thereof. Additional materials include polyetherimide and modified polyphenylene oxide. According to the embodiment shown in FIG.
  • the transmission line representation is able to handle various well casing scenarios, such as vertical only, slant wells, vertical and horizontal sections of casing, and, single or multiple insulating gaps, as well as the cement used to stabilize the well casing.
  • the electrically conductive proppant pack can include a plurality of electrically conductive proppant particles, each of the plurality of electrically conductive proppant particles can have a substantially uniform coating of electrically conductive material.
  • the substantially uniform coating of electrically conductive material can have any suitable thickness. In one or more exemplary embodiments, the substantially uniform coating of electrically conductive material can have a thickness of about 5 nm, about 10 nm, about 25 nm, about 50 nm, about 100 nm, or about 200 nm to about 300 nm, about 400 nm, about 500 nm, about 750 nm, about 1,000 about 1,500 nm, about 2,000 nm, or about 5,000 nm or more.
  • the thickness of the substantially uniform coating of electrically conductive material can be from about 10 nm to about 300 nm, from about 400 nm to about 1,000 nm, from about 200 nm to about 600 nm, or from about 100 nm to about 400 nm.
  • the electrically conductive proppant can include an irregular or non-uniform coating of electrically conductive material.
  • the nonuniform coating of electrically conductive material can cover or coat any suitable portion of the surface of a proppant particle.
  • the coating of electrically conductive material can cover at least about 10%, at least about 15%, at least about 20%), at least about 30%>, at least about 40%, or at least about 50% of the surface of the electrically conductive proppant particle.
  • the coating of electrically conductive material can cover less than 100%, less than 99%, less than 95%, less than 90%), less than 85%>, less than 80%>, less than 75%, less than 65%>, less than 50%, less than 40%), or less than 35% of the surface of the electrically conductive proppant particle. In one or more exemplary embodiments, about 25%, about 30%, about 35%, or about 45% to about 55%, about 65%, about 75%, about 85%, about 90%, about 95%, or about 99% or more of the surface of the electrically conductive proppant particle can be covered by the electrically conductive material.
  • the coating of electrically conductive material can cover from about 10% to about 99%, from about 15% to about 95%, from about 20% to about 75%, from about 25% to about 65%, from about 30% to about 45%, from about 35% to about 75%, from about 45% to about 90%, or from about 40% to about 95% of the surface of the electrically conductive proppant particle.
  • the non-uniform coating of electrically conductive material can have any suitable thickness.
  • the non-uniform coating of electrically conductive material can have an average thickness ranging from about 5 nm, about 10 nm, about 25 nm, about 50 nm, about 100 nm, or about 200 nm to about 300 nm, about 400 nm, about 500 nm, about 750 nm, about 1,000 about 1,500 nm, about 2,000 nm, or about 5,000 nm or more.
  • the average thickness of the non-uniform coating of electrically conductive material can be from about 400 nm to about 1,000 nm, from about 200 nm to about 600 nm, or from about 100 nm to about 400 nm.
  • the non-uniform coating of electrically conductive material can also have any suitable variation in thickness.
  • the thickness of the non-uniform coating of electrically conductive material can vary from about 10 nm to about 1,000 nm, from about 50 nm to about 500 nm, from about 100 nm to about 400 nm, or from about 400 nm to about 1,000 nm.
  • the electrically conductive proppant pack can have any suitable electrical conductivity.
  • the electrically conductive proppant pack can have an electrical conductivity of at least about 1 Siemen per meter (S/m), at least about 5 S/m, at least about 15 S/m, at least about 50 S/m, at least about 100 S/m, at least about 250 S/m, at least about 500 S/m, at least about 750 S/m, at least about 1,000 S/m, at least about 1,500 S/m, or at least about 2,000 S/m.
  • S/m Siemen per meter
  • the electrical conductivity of the pack can also be from about 10 S/m, about 50 S/m, about 100 S/m, about 500 S/m, about 1,000 S/m, or about 1,500 S/m to about 2,000 S/m, about 3,000 S/m, about 4,000 S/m, about 5,000 S/m, or about 6,000 S/m.
  • the electrically conductive proppant pack can have any suitable resistivity.
  • the pack can have a resistivity of less than 100 Ohm-cm, less than 80 Ohm-cm, less than 50 Ohm-cm, less than 25 Ohm-cm, less than 15 Ohm-cm, less than 5 Ohm-cm, less than 2 Ohm-cm, less than 1 Ohm-cm, less than 0.5 Ohm-cm, or less than 0.1 Ohm-cm.
  • the electrically conductive proppant pack can also include non-electrically conductive proppant in any suitable amounts.
  • the non-electrically conductive proppant can have any suitable resistivity.
  • the non-electrically conductive proppant can have a resistivity of at least about 1 x 10 5 Ohm-cm, at least about 1 x 10 8 Ohm-cm, at least about 1 x 10 10 Ohm-cm, at least about 1 x 10 11 Ohm-cm, or at least about 1 x 10 12 Ohm-cm.
  • the electrically conductive proppant pack can include any suitable amount of non-electrically conductive proppant.
  • the electrically conductive proppant pack can include at least about 1 wt%, at least about 5 wt%, at least about 10 wt%, at least about 20 wt%, at least about 40 wt%, at least about 50 wt%, at least about 60 wt%, at least about 70 wt%, at least about 80 wt%, at least about 90 wt%, or at least about 95 wt% non-electrically conductive proppant.
  • the electrically conductive proppant pack can include at least about 1 wt%, at least about 5 wt%, at least about 10 wt%, at least about 20 wt%, at least about 40 wt%, at least about 50 wt%, at least about 60 wt%, at least about 70 wt%, at least about 80 wt%, at least about 90 wt%, or at least about 95 wt% electrically conductive proppant.
  • the electrically conductive proppant pack can have an electrically conductive proppant concentration of about 2 wt%, about 4 wt%, about 8 wt%, about 12 wt%, about 25 wt%, about 35 wt%, or about 45 wt% to about 55 wt%, about 65 wt%, about 75 wt%, about 85 wt%, or about 95 wt% based on the total weight of the proppant pack.
  • the electrically conductive proppant pack can include from about 1 wt% to about 10 wt%, from about 10 wt% to about 25 wt%, about 25 wt% to about 50 wt%, from about 50 wt% to about 75 wt%, or from about 75 wt% to about 99 wt% non-electrically conductive proppant.
  • the non-electrically conductive proppant can be dispersed throughout the electrically conductive proppant pack in any suitable manner.
  • the non- electrically conductive proppant can be substantially evenly dispersed throughout the electrically conductive proppant pack.
  • the electrically conductive proppant pack containing the non-conductive proppant can have any suitable resistivity.
  • the electrically conductive proppant pack containing at least about 20 wt%, at least about 40 wt%, at least about 50 wt%, or at least about 60 wt% non-conductive proppant can have a resistivity of less than 1,000 Ohm-cm, less than 500 Ohm-cm, less than 200 Ohm-cm, less than 100 Ohm-cm, less than 80 Ohm-cm, less than 50 Ohm-cm, less than 25 Ohm-cm, less than 15 Ohm-cm, less than 5 Ohm-cm, less than 2 Ohm-cm, less than 1 Ohm-cm, less than 0.5 Ohm-cm, or less than 0.1 Ohm-cm.
  • the electrically conductive proppant pack containing the non-conductive proppant can have any suitable electrical conductivity.
  • the electrically conductive proppant pack containing at least about 20 wt%, at least about 40 wt%, at least about 50 wt%, or at least about 60 wt% non-conductive proppant can have an electrical conductivity of at least about 0.1 S/m, at least about 0.5 S/m, at least about 1 S/m, at least about 5 S/m, at least about 15 S/m, at least about 50 S/m, at least about 100 S/m, at least about 250 S/m, at least about 500 S/m, at least about 750 S/m, at least about 1,000 S/m, at least about 1,500 S/m, or at least about 2,000 S/m.
  • the electrically conductive proppant can be made from a conventional proppant such as a ceramic proppant, sand, plastic beads and glass beads.
  • a conventional proppant such as a ceramic proppant, sand, plastic beads and glass beads.
  • Such conventional proppants can be manufactured according to any suitable process including, but not limited to continuous spray atomization, spray fluidization, spray drying, or compression.
  • Suitable conventional proppants and methods for their manufacture are disclosed in U.S. Patent Nos. 4,068,718, 4,427,068, 4,440,866, 5,188,175, and 7,036,591, the entire disclosures of which are incorporated herein by reference.
  • Ceramic proppants vary in properties such as apparent specific gravity by virtue of the starting raw material and the manufacturing process.
  • apparent specific gravity is the weight per unit volume (grams per cubic centimeter) of the particles, including the internal porosity.
  • Low density proppants generally have an apparent specific gravity of less than 3.0 g/cm 3 and are typically made from kaolin clay and other alumina, oxide, or silicate ceramics.
  • Intermediate density proppants generally have an apparent specific gravity of about 3.1 to 3.4 g/cm 3 and are typically made from bauxitic clay.
  • High strength proppants are generally made from bauxitic clays with alumina and have an apparent specific gravity above 3.4 g/cm 3 .
  • sintered, substantially round and spherical particles, or proppants are prepared from a slurry of alumina-containing raw material.
  • the particles have an alumina content of from about 40% to about 55% by weight.
  • the sintered, substantially round and spherical particles have an alumina content of from about 41.5% to about 49% by weight.
  • the proppants have a bulk density of from about 1.35 g/cm 3 to about 1.55 g/cm 3 .
  • the proppants have a bulk density of from about 1.40 g/cm 3 to about 1.50 g/cm 3 .
  • the proppants have any suitable permeability and fluid conductivity in accordance with ISO 13503-5: "Procedures for Measuring the Long-term Conductivity of Proppants," and expressed in terms of Darcy units, or Darcies (D).
  • the proppants can have a long term permeability at 7,500 psi of at least about 1 D, at least about 2 D, at least about 5 D, at least about 10 D, at least about 20 D, at least about 40 D, at least about 80 D, at least about 120 D, or at least about 150 D.
  • the proppants can have a long term permeability at 12,000 psi of at least about 1 D, at least about 2 D, at least about 3 D, at least about 4 D, at least about 5 D, at least about 10 D, at least about 25 D, or at least about 50 D.
  • the proppants can have a long term conductivity at 7,500 psi of at least about 100 millidarcy-feet (mD-ft), at least about 200 mD-ft, at least about 300 mD-ft, at least about 500 mD-ft, at least about 1,000 mD-ft, at least about 1,500 mD-ft, at least about 2,000 mD-ft, or at least about 2,500 mD-ft.
  • mD-ft millidarcy-feet
  • the proppants can have a long term conductivity at 12,000 psi of at least about 50 mD-ft, at least about 100 mD-ft, at least about 200 mD-ft, at least about 300 mD-ft, at least about 500 mD-ft, at least about 1,000 mD-ft, or at least about 1,500 mD-ft.
  • the proppants have a crush strength at 10,000 psi of from about 5% to about 8.5%, and a long term fluid conductivity at 10,000 psi of from about 2500 mD-ft to about 3000 mD-ft. In certain other embodiments, the proppants have a crush strength at 10,000 psi of from about 5% to about 7.5%.
  • the proppants can have any suitable apparent specific gravity.
  • the proppants have an apparent specific gravity of less than 5, less than 4.5, less than 4.2, less than 4, less than 3.8, less than 3.5, or less than 3.2.
  • the proppants have an apparent specific gravity of from about 2.50 to about 3.00, about 2.75 to about 3.25, about 2.8 to about 3.4, about 3.0 to about 3.5, or about 3.2 to about 3.8.
  • the proppants can have a specific gravity of about 5 or less, about 4.5 or less, about 4.2 or less, about 4 or less, or about 3.8 or less.
  • the ceramic proppant can be manufactured in a manner that creates porosity in the proppant grain.
  • a process to manufacture a suitable porous ceramic proppant is described in U.S. Patent No. 7,036,591, the entire disclosure of which is incorporated herein by reference.
  • the electrically conductive material can be impregnated into the pores of the proppant grains to a concentration of about 0.01 wt%, about 0.05 wt%, about 0.1 wt%, about 0.5 wt%, about 1 wt%, about 2 wt%, or about 5 wt% to about 6 wt%, about 8 wt%, about 10 wt%, about 12 wt%, about 15 wt%, or about 20 wt% based on the weight of the electrically conductive proppant.
  • Water soluble coatings such as polylactic acid can be used to coat these particles to allow for delayed/timed release of conductive particles.
  • the ceramic proppants can have any suitable porosity.
  • the ceramic proppants can include an internal interconnected porosity from about 1%, about 2%, about 4%, about 6%, about 8%, about 10%, about 12%, or about 14% to about 18%, about 20%, about 22%, about 24%, about 26%, about 28%, about 30%, about 34%, about 38%, or about 45% or more.
  • the internal interconnected porosity of the ceramic proppants is from about 5 to about 35%, about 5 to about 15%, or about 15 to about 35%.
  • the ceramic proppants have any suitable average pore size.
  • the ceramic proppant can have an average pore size from about 2 nm, about 10 nm, about 15 nm, about 55 nm, about 110 nm, about 520 nm, or about 1, 100 nm to about 2,200 nm, about 5,500 nm, about 11,000 nm, about 17,000 nm, or about 25,000 nm or more in its largest dimension.
  • the ceramic proppant can have an average pore size from about 3 nm to about 30,000 nm, about 30 nm to about 18,000 nm, about 200 nm to about 9,000 nm, about 350 nm to about 4,500 nm, or about 850 nm to about 1,800 nm in its largest dimension.
  • Suitable sintered, substantially round and spherical particles can also include proppants manufactured according to vibration-induced dripping methods, herein called "drip casting.” Suitable drip casting methods and proppants made therefrom are disclosed in U.S. Patent Nos. 8,865,631, 8,883,693, and 9,175,210 and U.S. Patent Application Nos. 14/502,483 and 14/802,761, the entire disclosures of which are incorporated herein by reference. Proppants produced from the drip cast methods can have a specific gravity of at least about 2.5, at least about 2.7, at least about 3, at least about 3.3, or at least about 3.5.
  • Proppants produced from the drip cast methods can have a specific gravity of about 5 or less, about 4.5 or less, or about 4 or less.
  • the drip cast proppants can also have a surface roughness of less than 5 ⁇ , less than 4 ⁇ , less than 3 ⁇ , less than 2.5 ⁇ , less than 2 ⁇ , less than 1.5 ⁇ , or less than 1 ⁇ .
  • the drip cast proppants have an average largest pore size of less than about 25 ⁇ , less than about 20 ⁇ , less than about 18 ⁇ , less than about 16 ⁇ , less than about 14 ⁇ , or less than about 12 ⁇ and/or a standard deviation in pore size of less than 6 ⁇ , less than 4 ⁇ , less than 3 ⁇ , less than 2.5 ⁇ , less than 2 ⁇ , less than 1.5 ⁇ , or less than 1 ⁇ .
  • the drip cast proppants have less than 5,000, less than 4,500, less than 4,000, less than 3,500, less than 3,000, less than 2,500, or less than 2,200 visible pores at a magnification of 500x per square millimeter of proppant particle.
  • the proppants produced by the drip casting methods or the conventional methods, can have any suitable composition.
  • the proppants can be or include silica and/or alumina in any suitable amounts.
  • the proppants include less than 80 wt%, less than 60 wt%, less than 40 wt%, less than 30 wt%, less than 20 wt%, less than 10 wt%, or less than 5 wt% silica based on the total weight of the proppants.
  • the proppants include from about 0.1 wt% to about 70 wt% silica, from about 1 wt% to about 60 wt% silica, from about 2.5 wt% to about 50 wt% silica, from about 5 wt% to about 40 wt% silica, or from about 10 wt% to about 30 wt% silica.
  • the proppants include at least about 30 wt%, at least about 50 wt%, at least about 60 wt%, at least about 70 wt%, at least about 80 wt%, at least about 90 wt%, or at least about 95 wt% alumina based on the total weight of the proppants.
  • the proppants include from about 30 wt% to about 99.9 wt% alumina, from about 40 wt% to about 99 wt% alumina, from about 50 wt% to about 97 wt% alumina, from about 60 wt% to about 95 wt% alumina, or from about 70 wt% to about 90 wt% alumina.
  • the proppants produced by the processes disclosed herein can include alumina, bauxite, or kaolin, or any mixture thereof.
  • the proppants can be composed entirely of or composed essentially of alumina, bauxite, or kaolin, or any mixture thereof.
  • kaolin is well known in the art and can include a raw material having an alumina content of at least about 40 wt% on a calcined basis and a silica content of at least about 40 wt% on a calcined basis.
  • bauxite is well known in the art and can be or include a raw material having an alumina content of at least about 55 wt% on a calcined basis.
  • the proppants can also have any suitable size.
  • the proppants can have a size of at least about 100 mesh, at least about 80 mesh, at least about 60 mesh, at least about 50 mesh, or at least about 40 mesh.
  • the proppants can have a size from about 115 mesh to about 2 mesh, about 100 mesh to about 3 mesh, about 80 mesh to about 5 mesh, about 80 mesh to about 10 mesh, about 60 mesh to about 12 mesh, about 50 mesh to about 14 mesh, about 40 mesh to about 16 mesh, or about 35 mesh to about 18 mesh.
  • the proppants have a size of from about 20 to about 40 U.S. Mesh.
  • the proppants are made in a continuous process, while in other embodiments, the proppants are made in a batch process.
  • An electrically conductive material such as a metal, a conductive polymer, or a conductive particle may be added at any suitable stage in the manufacturing process of any one of these proppants to result in an electrically conductive proppant suitable for use according to certain embodiments of the present invention.
  • the electrically conductive material can also be added to any one of these proppants after manufacturing of the proppants.
  • the proppant can be a porous proppant, such that the electrically conductive material can be impregnated or infused into the pores of the proppant to provide the electrically conductive proppant.
  • the porous proppant can be impregnated or infused with the electrically conductive material in any suitable amounts, such as from about 1% to 15% by weight.
  • Water soluble coatings such as polylactic acid can be used to coat these particles to allow for delayed/timed release of conducting particles.
  • the electrically conductive material can be or include any suitable electrically conductive metal.
  • the metal can be or include iron, silver, gold, copper, aluminum, calcium, tungsten, zinc, nickel, lithium, platinum, palladium, rhodium, tin, carbon steel, or any combination or oxide thereof.
  • the electrically conductive material can be selected from one or more of aluminum, copper, nickel, and phosphorus and any alloy or mixture thereof.
  • the electrically conductive proppant can have an electrically conductive metal concentration of about 0.01 wt%, about 0.05 wt%, about 0.1 wt%, about 0.5 wt%, about 1 wt%, about 2 wt%, or about 5 wt% to about 6 wt%, about 8 wt%, about 10 wt%, about 12 wt%, or about 14 wt%.
  • the metals can include aluminum, copper and nickel and can be added to result in a proppant having a metal content of from about 5% to about 10% by weight.
  • the electrically conductive material can be or include any suitable electrically conductive polymer.
  • Suitable conductive polymers include polype- ethyl enedioxythiophene) poly(styrenesulfonate) (PEDOT:PSS), polyanilines (PANI), and polypyrroles (PPY) and can be added to result in a proppant having any suitable conductive polymer content, such as from about 0.1% to about 10% by weight.
  • the electrically conductive proppant can have a conductive polymer concentration of about 0.01 wt%, about 0.05 wt%, about 0.1 wt%, about 0.5 wt%, about 1 wt%, about 2 wt%, or about 5 wt% to about 6 wt%, about 8 wt%, about 10 wt%, about 12 wt%, or about 14 wt%.
  • Suitable PEDOT:PSS, PANI and PYY conductive polymers are commercially available from Sigma-Aldrich.
  • the electrically conductive material can be or include any suitable electrically conductive particle.
  • Suitable conductive particles include graphite, single or double-walled carbon nanotubes, or other material that when present in the nanoscale particle size range exhibits sufficient electrical conductivity to allow for detection in the present invention.
  • Suitable conductive particles can also include any suitable metal, such as iron, silver, gold, copper, aluminum, calcium, tungsten, zinc, nickel, lithium, platinum, tin, carbon steel, or any combination or oxide thereof.
  • Such conductive particles can be added to result in an electrically conductive proppant having a conductive particle concentration of about 0.01 wt%, about 0.05 wt%, about 0.1 wt%, about 0.5 wt%, about 1 wt%, about 2 wt%, or about 5 wt% to about 6 wt%, about 8 wt%, about 10 wt%, about 12 wt%, or about 14 wt%.
  • the electrically conductive proppant can have a conductive nanoparticle content of from about 0.1% to about 10% by weight.
  • the conductive particles can have any suitable size.
  • the conductive particles have a size from about 1 nanometers (nm), about 5 nm, about 10 nm, about 50 nm, about 100 nm, about 500 nm, or about 1,000 to about 2,000 nm, about 5,000 nm, about 10,000 nm, about 15,000 nm, or about 20,000 nm in its largest dimension.
  • the conductive particles can be from about 2 nm to about 25,000 nm, about 25 nm to about 15,000 nm, about 50 nm to about 10,000 nm, about 150 nm to about 7,500, about 250 nm to about 4,000 nm, or about 750 nm to about 1,500 nm in its largest dimension.
  • the conductive particles can also be from about 2 nm to about 2,000 nm, about 20 nm to about 500 nm, about 40 nm to about 300 nm, about 50 nm to about 250 nm, about 75 nm to about 200 nm, or about 100 nm to about 150 nm in its largest dimension.
  • the conductive particle is nano-sized or is a nanoparticle.
  • the conductive nanoparticle can have a size less than 500 nm, less than 250 nm, less than 150 nm, less than 100 nm, less than 95 nm, less than 90 nm, less than 85 nm, less than 80 nm, less than 75 nm, less than 70 nm, less than 65 nm, less than 60 nm, less than 55 nm, less than 50 nm, less than 45 nm, less than 40 nm, less than 35 nm, less than 30 nm, less than 25 nm, less than 20 nm, less than 15 nm, less than 10 nm, less than 5 nm, less than 2 nm, or less than 1 nm in its largest dimension.
  • the electrically conductive material can be added at any stage in a method of manufacture of a conventional ceramic proppant.
  • the method of manufacture of a conventional ceramic proppant can be or include a method similar in configuration and operation to that described in U.S. Patent No. 4,440,866, the entire disclosure of which a incorporated herein by reference.
  • the electrically conductive material can be added at any stage in a method of manufacture of drip cast proppant. Suitable drip casting methods and proppants made therefrom are disclosed in U.S. Patent Nos. 8,865,631 and 8,883,693, U.S. Patent Application Publication No. 2012/0227968, and U.S. Patent Application No. 14/502,483, the entire disclosures of which are incorporated herein by reference.
  • the electrically conductive material is coated onto the proppants to provide the electrically conductive proppant.
  • the coating may be accomplished by any coating technique well known to those of ordinary skill in the art such as spraying, sputtering, vacuum deposition, dip coating, extrusion, calendaring, powder coating, electroplating, transfer coating, air knife coating, roller coating and brush coating.
  • the electrically conductive material is coated onto the proppants with an electroless plating or coating method.
  • the electrically conductive material can also be incorporated into a resin material.
  • Ceramic proppant or natural sands can be coated with the resin material containing the electrically conductive material such as metal clusters, metal flake, metal shot, metal powder, metalloids, metal nanoparticles, quantum dots, carbon nanotubes, buckminsterfullerenes, and other suitable electrically conductive materials to provide electrically conductive material- containing proppant that can be detected by electromagnetic means.
  • Processes for resin coating proppants and natural sands are well known to those of ordinary skill in the art. For example, a suitable solvent coating process is described in U.S. Patent No. 3,929, 191, to Graham et al, the entire disclosure of which is incorporated herein by reference.
  • Another suitable process such as that described in U.S. Patent No. 3,492, 147 to Young et al, the entire disclosure of which is incorporated herein by reference, involves the coating of a particulate substrate with a liquid, uncatalyzed resin composition characterized by its ability to extract a catalyst or curing agent from a non-aqueous solution.
  • a suitable hot melt coating procedure for utilizing phenol-formaldehyde novolac resins is described in U.S. Patent No. 4,585,064, to Graham et al, the entire disclosure of which is incorporated herein by reference.
  • Those of ordinary skill in the art will be familiar with still other suitable methods for resin coating proppants and natural sands.
  • the electrically conductive material is incorporated into a resin material and ceramic proppant or natural sands are coated with the resin material containing the electrically conductive material.
  • Processes for resin coating proppants and natural sands are well known to those of ordinary skill in the art.
  • a suitable solvent coating process is described in U.S. Patent No. 3,929, 191, to Graham et al., the entire disclosure of which is incorporated herein by reference.
  • Another suitable process such as that described in U.S. Patent No.
  • the proppants disclosed herein are coated with a resin material to provide resin coated proppant particulates.
  • the electrically conductive material can be mixed with the resin material and coated onto the proppants to provide the resin coated proppant particulates.
  • at least a portion of the surface area of each of the resin coated proppant particulates is covered with the resin material.
  • at least about 10%, at least about 25%, at least about 50%, at least about 75%), less than 90%, less than 95%, or less than 99% of the surface area of the resin coated proppant particulates is covered with the resin material.
  • the resin coated proppant particulates can be encapsulated with the resin material.
  • the resin material is present on the resin coated proppant particulates in any suitable amount.
  • the resin coated proppant particulates contain at least about 0.1 wt% resin, at least about 0.5 wt% resin, at least about 1 wt% resin, at least about 2 wt% resin, at least about
  • the resin coated proppant particulates contain about 0.01 wt%, about 0.2 wt%, about 0.8 wt%, about 1.5 wt%, about 2.5 wt%, about 3.5 wt%, or about
  • the resin material includes any suitable resin.
  • the resin material can include a phenolic resin, such as a phenol- formaldehyde resin.
  • the phenol-formaldehyde resin has a molar ratio of formaldehyde to phenol (F:P) from a low of about 0.6: 1, about 0.9: 1, or about 1.2: 1 to a high of about 1.9: 1, about 2.1 : 1, about 2.3 : 1, or about 2.8: 1.
  • the phenol-formaldehyde resin can have a molar ratio of formaldehyde to phenol of about 0.7: 1 to about 2.7: 1, about 0.8: 1 to about 2.5: 1, about 1 : 1 to about 2.4: 1, about 1.1 : 1 to about 2.6: 1, or about 1.3 : 1 to about 2: 1.
  • the phenol-formaldehyde resin can also have a molar ratio of formaldehyde to phenol of about 0.8: 1 to about 0.9: 1, about 0.9: 1 to about 1 : 1, about 1 : 1 to about 1.1 : 1, about 1.1 : 1 to about 1.2: 1, about 1.2: 1 to about 1.3 : 1, or about 1.3 : 1 to about 1.4: 1.
  • the phenol-formaldehyde resin has a molar ratio of less than 1 : 1, less than 0.9: 1, less than 0.8: 1, less than 0.7: 1, less than 0.6: 1, or less than 0.5: 1.
  • the phenol-formaldehyde resin can be or include a phenolic novolac resin.
  • Phenolic novolac resins are well known to those of ordinary skill in the art, for instance see U.S. Patent No. 2,675,335 to Rankin, U.S. Patent No. 4, 179,429 to Hanauye, U.S. Patent No. 5,218,038 to Johnson, and U.S. Patent No.
  • novolac resins include novolac resins available from Plenco TM , Durite ® resins available from Momentive, and novolac resins available from S.I. Group.
  • the conducting particles disclosed herein can be infused into a porosity of the proppant particles.
  • one or more conducting particles can be infused into the porous structure of a proppant particle that is then coated with a coating that allows the conducting particles to elute from the pores of the proppant particle and rest at or near the outer surface of the proppant particle.
  • the conducting particles can also be infused into and elute from the proppant particles in any suitable manner disclosed in U.S. Patent Application No. 14/629,004, which is incorporated herein by reference in its entirety.
  • the conducting particles can be introduced into the one or more subterranean fractures in any suitable manner.
  • the conducting particles can be mixed with a slurry of non-electrically conductive proppant to provide a conducting particle/non- electrically conductive proppant mixture at or near the surface.
  • the conducting particle/non- electrically conductive proppant mixture can then be introduced into one or more subterranean fractures during any suitable hydraulic fracturing operation to provide an electrically conductive proppant pack when the conducting particles come to rest at or near the outer surfaces of the proppant in the proppant pack, making the proppant pack electrically conductive.
  • any combination of the conductive particles and non-electrically conductive proppant can be introduced into one or more fractures to provide an electrically conductive proppant pack.
  • the conductive particles are treated and/or coated with one or more chemicals or ligands to impart surface functionality to the conductive particles.
  • These coatings can be selected from organic compound containing materials and/or organic compounds of varying chain lengths, each having functional groups on the terminus of their respective chains to modify or tailor the solubility (solubility, as used herein, also refers to a suspension or slurry) of the conductive particles in a produced fluid.
  • These coatings can also be selected from organic compound containing materials and/or organic compounds of varying chain lengths, each having functional groups on the terminus of their respective chains to modify a surface functionality of the conductive particles so that they have an affinity for an outer surface of the proppant material in a proppant pack. These coatings can also be selected from organic compound containing materials and/or organic compounds of varying chain lengths, each having functional groups on the terminus of their respective chains to modify a surface functionality of the conductive particles so that they have an affinity for a resin coating of the resin coated proppant. Many commercially available surfactants can be used for these purposes.
  • Ligands that are multi-functional can also be used as a coating, with one end of the ligand molecule binding to the conductive particle and the other end of the ligand molecule affecting the dispersibility of the conductive particle throughout a proppant pack.
  • These multi-functional ligands can be modified by traditional organic synthetic methods and principles to increase or decrease the affinity of the conductive particles to the outer surfaces of the proppants in the proppant pack.
  • Examples of the types of functional groups that can be used are carboxylates, amines, thiols, polysiloxanes, silanes, alcohols, and other species capable of binding to the conductive particle or the proppant surface.
  • At least a portion of the conductive particles can remain at or near the proppant surface(s) of the proppant pack because the conductive particles have a greater affinity for the resin coat on the proppant particulates and/or outer surfaces of the proppant particulates than for fracturing fluid(s) and/or produced fluid(s).
  • FIG. 7A depicts an induced fracture 700 in an open state 702, or pre-closed state, containing an electrically conductive proppant pack under a first load 704.
  • the induced fracture 700 can extend approximately perpendicularly outward from a well casing that is in electrical communication with an electric current source located in the well casing, on the surface at or near the well casing, and/or in an adjacent wellbore.
  • the electrically conductive proppant pack is in electrical communication with a plurality of electric and/or magnetic field sensors located at or near the surface and/or in one or more adjacent wellbores.
  • the fracture 700 can be or include the proppant filled fracture 32.
  • the proppant filled fracture 32 can be in the open state 702 and can include the electrically conductive proppant pack under the first load 704.
  • the term "open state” refers to the condition of the fracture and the proppant pack contained therein prior to leak-off of fracturing fluid that occurs when the injection pressure of the fracturing fluid is released. After sufficient leak-off, the fracture will close, causing the fracture to transition from the open state 702 to the closed state.
  • FIG. 7B depicts the fracture 700 in a closed state 706 containing the electrically conductive proppant pack of FIG. 7A under a second load 708.
  • the term “closed state” refers to the condition of the fracture and the proppant pack contained therein after leak-off of the fracturing fluid due to the injection pressure of the fracturing fluid being released.
  • At least a portion of the electric current generated by the source can travel from the well casing, such as well casing 22, and through the proppant in the fracture 700. Electromagnetic fields generated by the current in the well casing and that propagate to various locations in a volume of Earth can be altered by the presence of the electrically conductive proppant pack following the injection of the electrically conductive proppant into the fracture 700. Electromagnetic fields generated by the currents in both the well casing and the proppant pack propagate to various locations in a three-dimensional volume of Earth and are sensed, using the sensors 38 for example.
  • an increased closure pressure or load onto the electrically conductive proppant pack due to the closing fracture can result in an increase in the electrical conductivity of the electrically conductive proppant pack.
  • increasing a load onto the pack of the electrically conductive proppant pack by a factor of 2, a factor of 5, or a factor of 10 can increase the electrical conductivity of the pack of the electrically conductive proppant by at least about 50%, at least about 75%, at least about 100%), at least about 150%, or at least about 200%.
  • increasing a load onto the pack of the electrically conductive proppant pack by a factor of 2, a factor of 5, or a factor of 10 can decrease the resistivity of the pack of the electrically conductive proppant pack 200 by from about 1%, about 2%, or about 5% to about 10%, about 15%, or about 25%.
  • the increase or change of the electrical conductivity and/or resistivity of the electrically conductive proppant pack can be detected to determine fracture closure and/or fracture closure time.
  • a change in the electrical conductivity and/or resistivity of the electrically conductive proppant pack along one or more time intervals can be detected and chronicled to determine fracture closure and fracture closure time.
  • the fracture closure time can be determined when there are no further changes observed in the electrical conductivity and/or resistivity of the electrically conductive proppant pack. For example, no change detected in the electrical conductivity and/or resistivity of the electrically conductive proppant pack over two or more, three or more, four or more, five or more, or ten or more consecutive time intervals can indicate fracture closure.
  • the detection of closure and determination of closure time of a fracture will depend upon several factors, including but not limited to the net electrical conductivity of the fracture, fracture volume, the electrical conductivity, magnetic permeability, and electric permittivity of the earth surrounding the fracture and between the fracture and surface mounted sensors.
  • the net electrical conductivity of the fracture means the combination of the electrical conductivity of the fracture, the proppant and the fluids when all are placed in the earth minus the electrical conductivity of the earth formation when the fracture, proppant and fluids were not present.
  • the total electrical conductivity of the proppant filled fracture is the combination of the electrical conductivity created by making a fracture, plus the electrical conductivity of the new/modified proppant plus the electrical conductivity of the fluids, plus the electro-kinetic effects of moving fluids through a porous body such as a proppant pack.
  • the volume of an overly simplified fracture with the geometric form of a plane may be determined by multiplying the height, length, and width (i.e. gap) of the fracture.
  • a three dimensional (3D) finite-difference electromagnetic algorithm that solves Maxwell's equations of electromagnetism may be used for numerical simulations.
  • the net fracture conductivity multiplied by the fracture volume within one computational cell of the finite difference (FD) grid must be larger than approximately 100 Sm 2 for a Barnett shale-like model where the total fracture volume is approximately 38 m 3 .
  • the depth of the fracture is 2000 m.
  • the measured three dimensional components of the electric and magnetic field responses may be analyzed with imaging methods such as an inversion algorithm based on Maxwell's equations and electromagnetic migration and/or holography to determine proppant pack location and the closure time of the fracture surrounding the proppant pack.
  • Inversion of acquired data to determine proppant pack location and the closure time of the fracture containing the proppant pack involves adjusting the earth model parameters, including but not limited to the proppant location within a fracture or fractures and the net electrical conductivity of the fracture, to obtain the best fit to forward model calculations of responses for an assumed earth model. As described in Bartel, L.
  • the electromagnetic integral wave migration method utilizes Gauss's theorem where the data obtained over an aperture are projected into the subsurface to form an image of the proppant pack.
  • the electromagnetic holographic method is based on the seismic holographic method and relies on constructive and destructive interferences where the data and the source wave form are projected into an earth volume to form an image of the proppant pack.
  • EH Maxwell's equations of electromagnetism with constitutive relations appropriate for time-independent isotropic media yields a system of six coupled first-order partial differential equations referred to as the "EH" system.
  • the name derives from the dependent variables contained therein, namely the electric vector E and the magnetic vector H.
  • Coefficients in the EH system are the three material properties, namely electrical current conductivity, magnetic permeability, and electric permittivity. All of these parameters may vary with 3D spatial position.
  • the inhomogeneous terms in the EH system represent various body sources of electromagnetic waves, and include conduction current sources, magnetic induction sources, and displacement current sources.
  • Conduction current sources representing current flow in wires, cables, and borehole casings, are the most commonly-used sources in field electromagnetic data acquisition experiments.
  • an explicit, time-domain, finite- difference (TDFD) numerical method is used to solve the EH system for the three components of the electric vector E and the three components of the magnetic vector H, as functions of position and time.
  • a three-dimensional gridded representation of the electromagnetic medium parameters referred to as the "earth model” is required, and may be constructed from available geophysical logs and geological information.
  • a magnitude, direction, and waveform for the current source are also input to the algorithm.
  • the waveform may have a pulse-like shape (as in a Gaussian pulse), or may be a repeating square wave containing both positive and negative polarity portions, but is not limited to these two particular options.
  • Execution of the numerical algorithm generates electromagnetic responses in the form of time series recorded at receiver locations distributed on or within the gridded earth model. These responses represent the three components of the E or H vector, or their time-derivatives.
  • the finite-difference numerical algorithm enables a quantitative estimate of the magnitude and frequency-content of electromagnetic responses (measured on the earth's surface or in nearby boreholes) to be made as important modeling parameters are varied.
  • the depth of current source may be changed from shallow to deep.
  • the current source may be localized at a point, or may be a spatially- extended transmission line, as with an electrically charged borehole casing.
  • the source waveform may be broad-band or narrow-band in spectral content.
  • changes to the electromagnetic earth model can be made, perhaps to assess the shielding effect of shallow conductive layers.
  • the goal of such a modeling campaign is to assess the sensitivity of recorded electromagnetic data to variations in pertinent parameters. In turn, this information is used to design optimal field data acquisition geometries that have enhanced potential for imaging a proppant-filled fracture at depth.
  • the electric and magnetic responses are scalable with the input current magnitude.
  • a large current on the order of 10 to 100 amps may be required.
  • the impedance of the electric cable to the current contact point and the earth contact resistance will determine the voltage that is required to obtain a desired current.
  • the contact resistance is expected to be small and will not dominate the required voltage.
  • a time-domain current source waveform may be used, but not limited to a time-domain waveform.
  • a typical time-domain waveform consists of an on time of positive current followed by an off time followed by an on time of negative current.
  • the repetition rate to be used would be determined by how long the current has to be on until a steady-state is reached or alternatively how long the energizing current has to be off until the fields have died to nearly zero.
  • the measured responses would be analyzed using the rise time fields following current turn-on, the steady-state values, and the decaying fields following the current shut-off.
  • the off period of the time domain input signal allows analysis of the direct current electrical fields that may arise from electro-kinetic effects, including but not limited to, flowing fluids and proppant during the fracturing process.
  • Fracture properties orientation, length, volume, height and asymmetry will be determined through inversion of the measured data and/or a form of holographic reconstruction of that portion of the earth (fracture) that yielded the measured electrical responses or secondary fields.
  • a pre-fracture survey will be prepared to isolate the secondary fields due to the fracture.
  • a frequency domain finite-difference (FDFD) numerical method is used to solve the EH system for the three components of the electric vector E and the three components of the magnetic vector H.
  • the earth model, magnitude, direction, and waveform for the current source can be inputted to the algorithm.
  • the waveform may have a pulse-like shape (as in a Gaussian pulse), or may be a repeating square wave containing both positive and negative polarity portions, but is not limited to these two particular options.
  • Execution of the numerical algorithm generates electromagnetic responses in the form of frequency series recorded at receiver locations distributed on or within the gridded earth model. These responses represent the three components of the E or H vector, or their frequency- dependencies.
  • an induced polarization (IP) effect is used to determine a location of the proppant and a closure time of the fracture containing the proppant.
  • the IP effect is present in the time domain where the effect is measured following the cessation of the driving electric field.
  • the IP effect is also present in the frequency domain wherein the effect is explained in terms of complex impedance. For time domain measurements the received voltage decay as a function of time is made when the input current is off. The frequency domain measures the phase delay from the input current and the effects of frequency on the received voltage.
  • the IP effect arises from various causes and different dependencies on the frequency of an impressed electric field. Central to some of the theories is fluid flow in porous media. In a porous medium the earth material is generally slightly negatively charged, thereby attracting positive charged ions in the fluid that makes up the electric double layer (EDL). This leaves the fluid in the pore space somewhat rich in negative charges that now conduct current in a porous medium. The ionic current is the difference in the concentrations of positive and negative ions. The flow of ions takes place due to an impressed electric field, pressure gradient, and/or diffusion where the pore space available for transport is restricted by the EDL. In addition, there are other restrictions for flow (pore throats, other material in the pore space) that can cause charge build up.
  • EDL electric double layer
  • a metallic ore which is an electronic conductor, also affects the flow of the ions.
  • the charge distribution "wants" to seek a lower energy state, which is the equilibrium condition. Diffusion of charges plays a major role in the quest to obtain equilibrium.
  • a discontinuity is formed at the interface where such physicochemical variables as electric potential and electrolyte concentration change significantly from the aqueous phase to another phase.
  • charge separation often occurs at the interfacial region.
  • This interfacial region, together with the charged surface is usually known as the EDL.
  • This EDL, or layer which can extend as far as 100 nm in a very dilute solution to only a few angstroms in a concentrated solution, plays an important role in electrochemistry, colloid science, and surface chemistry.
  • the component of the electric field perpendicular to the direction of the fracture will generally be larger than the component parallel to the fracture.
  • the component of the electric field parallel to the fracture will induce ionic conductivity in the fracture fluid that will be impeded due to the ion mobility in the presence of the EDL and the charges induced on the conductive proppant.
  • the current flow perpendicular to the fracture will not depend appreciably on the ionic flow but more on electronic conduction via the metallic coated proppant particles.
  • the electronic conduction of electrical current will depend on the volume of the metal present and will rely on proppant particles to be in contact with each other.
  • Another EM response that impacts IP measurements is the inductive response of the earth.
  • the inductive response arises from the Faraday/Lentz law which produces eddy currents in conductive media.
  • the response is based upon the time-rate-of-change of the magnetic field; if the magnetic field is increasing, eddy currents are generated in the conductor (earth) to create a magnetic field opposite to the increasing magnetic field, and if the magnetic field is decreasing eddy currents are generated in the conductor to create a magnetic field opposite that of the decreasing magnetic field.
  • the finite-difference solutions to Maxwell's equations includes the inductive responses, but not the IP responses.
  • the IP effects can be included into the FDEM algorithm by treating the IP effect as a time dependent source term. If the IP effect is treated as a time dependent source term, then the IP effect can be much larger than the pure conductive response.
  • the closure of a subterranean fracture containing electrically conductive proppant can be determined by introducing a plurality or series of discrete electric currents (ai .... aN) into the fracture.
  • N can be any integer greater than 1.
  • N can be 2, 3, 4, 5, 6, 7, 8, or 9 or more.
  • the series of electric currents (ai .... a ⁇ can correspond to a series of EM field measurements (bi . . . . bN) so that bi is a measurement of the electric current ai, b 2 is a measurement of the electric current a 2 and so on.
  • the amount and/or extent of fracture closure can be determined by iteratively comparing measurements bN to b N +i to check for differences between two successive measurements. No difference or no substantial difference between successive measurements bN and bN+i can indicate closure of the fracture.
  • the closure time of a fracture can be determined by introducing a series of discrete electric currents (ai .... aN) into the fracture and obtaining the corresponding EM field measurements (bi . . . . bN) over a period of time.
  • the period of time can be or include any selected period of time between injecting an electrically conductive proppant containing slurry into the fracture and when closure of the fracture is indicated by no difference or no substantial difference between successive measurements b N and bN + i.
  • the period of time from injection of an electrically conductive proppant containing slurry into the fracture to the time in which no difference or no substantial difference between measurements bN and bN + i is indicated can be the closure time of the fracture.
  • a field data acquisition experiment was conducted to test the transmission line representation of a well casing current source.
  • the calculated electric field and the measured electric field are in good agreement.
  • This test demonstrates that the transmission line current source implementation in the 3D finite-difference electromagnetic code gives accurate results.
  • the agreement of course, depends upon an accurate model describing the electromagnetic properties of the earth.
  • common electrical logs were used to characterize the electrical properties of the earth surrounding the test well bore and to construct the earth model.
  • the sputter chamber had three articulating 2 inch target holders that can be used to coat complex shapes.
  • the system also had a rotating, water-cooled sample stage that was used in a sputter-down configuration.
  • deposition rates for the three metals were determined by sputtering the metals onto silicon wafers and measuring the coating thickness by scanning electron microscope (SEM) cross-sectional analysis with a Zeiss Neon 40 SEM.
  • the proppants were loaded into the sputter chamber in a 12 inch diameter aluminum pan with 1 inch tall sides. Approximately 130 g of proppant was used for each coating run. This amount of proppant provided roughly a single layer of proppant on the base of the pan. The proppant was "stirred” during the deposition using a 6 inch long fine wire metal that was suspended above the pan and placed into contact with the proppant in the pan. The coating deposition times were doubled compared to what was determined from the silicon wafer coating thickness measurements to account for roughly coating the proppants on one side, rolling them over, and then coating the other side. Coatings of approximately 100 nm and approximately 500 nm were deposited on each type of proppant with each of the three metals.
  • the proppant was inspected visually and by optical microscopy. The results indicated that the proppant having a thinner coating of approximately 100 nm had a generally non-uniform coating while the proppant with the thicker coating of approximately 500 nm had a uniform coating.
  • test system 1000 included an insulating boron nitride die 1002, having an inside diameter of 0.5 inches and an outside diameter of 1.0 inches, disposed in a bore 1004 in a steel die 1006 in which the bore 1004 had an inside diameter of 1.0 inches.
  • Upper and lower steel plungers 1008 and 1010 having an outside diameter of 0.5 inches were inserted in the upper and lower ends 1012, 1014, respectively, of the insulating boron nitride die 1002 such that a chamber 1016 is formed between the leading end 1018 of the upper plunger 208, the leading end 1020 of the lower plunger 1010 and the inner wall 1022 of the boron nitride sleeve 1002.
  • Upper plunger 1008 was removed from the insulating boron nitride die 1002 and proppant was loaded into the chamber 1016 until the proppant bed 1024 reached a height of about 1 to 2 cm above the leading end 1020 of the lower plunger 1010.
  • the upper plunger 1008 was then reinstalled in the insulating boron nitride die 1002 until the leading end 1018 of the upper plunger 1008 engaged the proppant 1024.
  • a copper wire 1026 was connected to the upper plunger 1008 and one pole of each of a current source 1028 and a voltmeter 1030.
  • a second copper wire was connected to the lower plunger 1010 and the other pole of each of the current source 1028 and the voltmeter 1030.
  • the current source may be any suitable DC current source well known to those of ordinary skill in the art such as a Keithley 237 High Voltage Source Measurement Unit in the DC current source mode and the voltmeter may be any suitable voltmeter well known to those of ordinary skill in the art such as a Fluke 175 True RMS Multimeter which may be used in the DC mV mode for certain samples and in the ohmmeter mode for higher resistance samples.
  • the current source was powered on and the resistance of the test system 1000 with the proppant bed 1024 in the chamber 1016 was then determined.
  • the resistance of the proppant 1024 was then measured with the Multimeter as a function of pressure using the upper plunger 1008 and lower plunger 1010 both as electrodes and to apply pressure to the proppant bed 1024.
  • R V/I - the resistance of the system with the plungers touching is subtracted from the values measured with the proppant bed 1024 in the chamber 1016 and the resistivity
  • p R*A/t where A is the area occupied by the proppant bed 1024 and t is the thickness of the proppant bed 1024 between the upper plunger 1008 and the lower plunger 1010.
  • CarboProp 40/70 2 x 10 12 Ohm-cm
  • CarboProp 20/40 0.6 x 10 12 Ohm-cm
  • Table I shows data for mixtures of CARBOLITE 20/40 with a 500 nm coating of aluminum and CARBOLITE 20/40 with no added conductive material.
  • 3 g. of the sample material was placed in the 0.5 inch die to provide an area of 0.196 square inches.
  • the applied current for each test was 5 raA and the tests were conducted at room temperature.
  • Table II shows data for mixtures of HYDROPROP 40/80 with a 500 nm coating of aluminum and HYDROPROP 40/80 with no added conductive material.
  • 3 g. of the sample material was placed in the 0.5 inch die to provide an area of 0.196 square inches.
  • the applied current for each test was 5 mA and the tests were conducted at room temperature.
  • Example 3 Electrical measurements of proppants with coatings of nickel and copper were also conducted. The results are shown in TABLE III below and FIG. 9.
  • TABLE III shows data for CARBOLITE 20/40 with a coating of nickel and CARBOLITE 20/40 with a coating of copper.
  • the sample material was placed in the 0.5 inch die. The applied voltage for each test was 0.005V.
  • This example is a prophetic example based on an expected change in measured field values for proppant conductivity increasing from 1,000 S/m to 5,000 S/m.
  • a computer simulation utilized an observed earth model containing a horizontal well. The simulation included a current injection of 20 Amps and two electric field sensors separated by 80 meters (m). The simulation also included simulated fracture zones in which lab results of nickel coated proppant particulates were utilized.
  • the distance x extends parallel to the horizontal section of the well track.
  • the spacing on the calculated results is 500 m.
  • the peak of the inductive response was observed at 0.04 seconds after current injection.
  • FIG. 11 shows that the magnitude of the response for the more conductive proppant is less than for the lesser conductive proppant.
  • the reason for his is two-fold: (1) due to the conductivity of the proppant, the magnitude of the electric field inside the proppant pack of 5,000 S/m is less than for the 1,000 S/m proppant pack and this difference manifests itself at the surface, and (2) the secondary electromagnetic induction fields for the 5,000 S/m material are larger than for the 1,000 S/m material and, due to Lentz's law, leads to a larger field in opposition to an increasing primary magnetic field in the conducting earth. These induction responses manifest themselves as a reduction of the measured response.
  • Table V The simulated data used in FIG. 11 is shown in Table V below.
  • the particles described herein may be handled in the same manner as ordinary proppants.
  • the particles may be delivered to the well site in bags or in bulk form along with the other materials used in fracturing treatment.
  • Conventional equipment and techniques may be used to place the particles in the formation as a proppant.
  • the particles are mixed with a fracture fluid, which is then injected into a fracture in the formation.
  • a hydraulic fluid is injected into the formation at a rate and pressure sufficient to open a fracture therein, and a fluid containing sintered, substantially round and spherical particles prepared from a slurry as described herein and having one or more of the properties as described herein is injected into the fracture to prop the fracture in an open condition.

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Abstract

L'invention concerne des procédés et des systèmes servant à déterminer une fermeture de fracture souterraine. Les procédés peuvent comprendre l'alimentation électrique d'un tubage d'un puits de forage qui s'étend depuis une surface de la terre dans une formation souterraine ayant une fracture qui est au moins partiellement remplie d'un agent de soutènement électro-conducteur et la mesure d'une première réponse de champ électrique à la surface ou dans un puits de forage adjacent à un premier intervalle de temps pour fournir une première mesure de champ. Les procédés peuvent également comprendre la mesure d'une seconde réponse de champ électrique à la surface ou dans le puits de forage adjacent à un second intervalle de temps pour fournir une seconde mesure de champ et déterminer une augmentation de la pression de fermeture sur l'agent de soutènement électro-conducteur à partir d'une différence entre les première et seconde mesures de champ.
PCT/US2016/061946 2015-11-16 2016-11-15 Procédés et systèmes de détermination d'une fermeture de fracture souterraine WO2017087348A1 (fr)

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CN201680078520.1A CN108474248A (zh) 2015-11-16 2016-11-15 用于确定地下裂缝闭合的方法和系统

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US14/942,304 US10267134B2 (en) 2013-01-04 2015-11-16 Methods and systems for determining subterranean fracture closure
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US20090288820A1 (en) * 2008-05-20 2009-11-26 Oxane Materials, Inc. Method Of Manufacture And The Use Of A Functional Proppant For Determination Of Subterranean Fracture Geometries
US20140000357A1 (en) * 2010-12-21 2014-01-02 Schlumberger Technology Corporation Method for estimating properties of a subterranean formation
US20150184065A1 (en) * 2013-01-04 2015-07-02 Carbo Ceramics Inc. Electrically conductive proppant and methods for detecting, locating and characterizing the electrically conductive proppant

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CN103291272B (zh) * 2013-06-14 2015-06-17 中国石油大学(华东) 一种基于磁性支撑剂的支撑剂铺置控制系统及控制方法

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Publication number Priority date Publication date Assignee Title
US20090288820A1 (en) * 2008-05-20 2009-11-26 Oxane Materials, Inc. Method Of Manufacture And The Use Of A Functional Proppant For Determination Of Subterranean Fracture Geometries
US20140000357A1 (en) * 2010-12-21 2014-01-02 Schlumberger Technology Corporation Method for estimating properties of a subterranean formation
US20150184065A1 (en) * 2013-01-04 2015-07-02 Carbo Ceramics Inc. Electrically conductive proppant and methods for detecting, locating and characterizing the electrically conductive proppant

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