US20100101783A1 - Using self-regulating nuclear reactors in treating a subsurface formation - Google Patents

Using self-regulating nuclear reactors in treating a subsurface formation Download PDF

Info

Publication number
US20100101783A1
US20100101783A1 US12/576,722 US57672209A US2010101783A1 US 20100101783 A1 US20100101783 A1 US 20100101783A1 US 57672209 A US57672209 A US 57672209A US 2010101783 A1 US2010101783 A1 US 2010101783A1
Authority
US
United States
Prior art keywords
formation
temperature
self
depicts
heater
Prior art date
Legal status (The legal status 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 status listed.)
Abandoned
Application number
US12/576,722
Other languages
English (en)
Inventor
Harold J. Vinegar
Scott Vinh Nguyen
Current Assignee (The listed assignees may be inaccurate. Google has not performed a legal analysis and makes no representation or warranty as to the accuracy of the list.)
Shell USA Inc
Original Assignee
Individual
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
Application filed by Individual filed Critical Individual
Priority to US12/576,722 priority Critical patent/US20100101783A1/en
Assigned to SHELL OIL COMPANY reassignment SHELL OIL COMPANY ASSIGNMENT OF ASSIGNORS INTEREST (SEE DOCUMENT FOR DETAILS). Assignors: VINEGAR, HAROLD J, NGUYEN, SCOTT VINH
Publication of US20100101783A1 publication Critical patent/US20100101783A1/en
Priority to US15/085,561 priority patent/US20160281482A1/en
Abandoned legal-status Critical Current

Links

Images

Classifications

    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2401—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection by means of electricity
    • 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
    • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
    • E21B44/02—Automatic control of the tool feed
    • H—ELECTRICITY
    • H01—ELECTRIC ELEMENTS
    • H01C—RESISTORS
    • H01C3/00—Non-adjustable metal resistors made of wire or ribbon, e.g. coiled, woven or formed as grids
    • H—ELECTRICITY
    • H05—ELECTRIC TECHNIQUES NOT OTHERWISE PROVIDED FOR
    • H05B—ELECTRIC HEATING; ELECTRIC LIGHT SOURCES NOT OTHERWISE PROVIDED FOR; CIRCUIT ARRANGEMENTS FOR ELECTRIC LIGHT SOURCES, IN GENERAL
    • H05B3/00—Ohmic-resistance heating
    • H05B3/40—Heating elements having the shape of rods or tubes
    • H05B3/42—Heating elements having the shape of rods or tubes non-flexible
    • H05B3/48—Heating elements having the shape of rods or tubes non-flexible heating conductor embedded in insulating material
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
    • E21B43/16—Enhanced recovery methods for obtaining hydrocarbons
    • E21B43/24—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection
    • E21B43/2405—Enhanced recovery methods for obtaining hydrocarbons using heat, e.g. steam injection in association with fracturing or crevice forming processes
    • H—ELECTRICITY
    • H05—ELECTRIC TECHNIQUES NOT OTHERWISE PROVIDED FOR
    • H05B—ELECTRIC HEATING; ELECTRIC LIGHT SOURCES NOT OTHERWISE PROVIDED FOR; CIRCUIT ARRANGEMENTS FOR ELECTRIC LIGHT SOURCES, IN GENERAL
    • H05B2214/00—Aspects relating to resistive heating, induction heating and heating using microwaves, covered by groups H05B3/00, H05B6/00
    • H05B2214/03—Heating of hydrocarbons
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y10—TECHNICAL SUBJECTS COVERED BY FORMER USPC
    • Y10T—TECHNICAL SUBJECTS COVERED BY FORMER US CLASSIFICATION
    • Y10T29/00—Metal working
    • Y10T29/49—Method of mechanical manufacture
    • Y10T29/49002—Electrical device making
    • Y10T29/49082—Resistor making
    • Y10T29/49083—Heater type

Definitions

  • the present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various subsurface formations such as hydrocarbon containing formations.
  • Hydrocarbons obtained from subterranean formations are often used as energy resources, as feedstocks, and as consumer products.
  • Concerns over depletion of available hydrocarbon resources and concerns over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources.
  • In situ processes may be used to remove hydrocarbon materials from subterranean formations that were previously inaccessible and/or too expensive to extract using available methods.
  • Chemical and/or physical properties of hydrocarbon material in a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation and/or increase the value of the hydrocarbon material.
  • the chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material in the formation.
  • wells or wellbores may be used to treat the hydrocarbon containing formation using an in situ heat treatment process.
  • vertical and/or substantially vertical wells are used to treat the formation.
  • horizontal or substantially horizontal wells (such as J-shaped wells and/or L-shaped wells), and/or u-shaped wells are used to treat the formation.
  • combinations of horizontal wells, vertical wells, and/or other combinations are used to treat the formation.
  • wells extend through the overburden of the formation to a hydrocarbon containing layer of the formation. In some situations, heat in the wells is lost to the overburden. In some situations, surface and overburden infrastructures used to support heaters and/or production equipment in horizontal wellbores or u-shaped wellbores are large in size and/or numerous.
  • Wellbores for heater, injection, and/or production wells may be drilled by rotating a drill bit against the formation.
  • the drill bit may be suspended in a borehole by a drill string that extends to the surface.
  • the drill bit may be rotated by rotating the drill string at the surface.
  • Sensors may be attached to drilling systems to assist in determining direction, operating parameters, and/or operating conditions during drilling of a wellbore. Using the sensors may decrease the amount of time taken to determine positioning of the drilling systems.
  • Heaters may be placed in wellbores to heat a formation during an in situ process.
  • heaters There are many different types of heaters which may be used to heat the formation. Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Pat. No. 2,634,961 to Ljungstrom; U.S. Pat. No. 2,732,195 to Ljungstrom; U.S. Pat. No. 2,780,450 to Ljungstrom; U.S. Pat. No. 2,789,805 to Ljungstrom; U.S. Pat. No. 2,923,535 to Ljungstrom; U.S. Pat. No. 4,886,118 to Van Meurs et al.; and U.S. Pat. No. 6,688,387 to Wellington et al.; each of which is incorporated by reference as if fully set forth herein.
  • Patent Application Publication No. 2009-0095476 to Nguyen et al. which is incorporated herein by reference, describes a heating system for a subsurface formation that includes a conduit located in an opening in the subsurface formation.
  • An insulated conductor is located in the conduit.
  • a material is in the conduit between a portion of the insulated conductor and a portion of the conduit.
  • the material may be a salt.
  • the material is a fluid at operating temperature of the heating system. Heat transfers from the insulated conductor to the fluid, from the fluid to the conduit, and from the conduit to the subsurface formation.
  • In situ production of hydrocarbons from tar sand may be accomplished by heating and/or injecting fluids into the formation.
  • U.S. Pat. No. 4,084,637 to Todd; U.S. Pat. No. 4,926,941 to Glandt et al.; U.S. Pat. No. 5,046,559 to Glandt, and U.S. Pat. No. 5,060,726 to Glandt each of which are incorporated herein by reference, describe methods of producing viscous materials from subterranean formations that includes passing electrical current through the subterranean formation. Steam may be injected from the injector well into the formation to produce hydrocarbons.
  • Embodiments described herein generally relate to systems, methods, and heaters for treating a subsurface formation. Embodiments described herein also generally relate to heaters that have novel components therein. Such heaters can be obtained by using the systems and methods described herein.
  • the invention provides one or more systems, methods, and/or heaters.
  • the systems, methods, and/or heaters are used for treating a subsurface formation.
  • an in situ heat treatment system for producing hydrocarbons from a subsurface formation includes: a plurality of wellbores in the formation; at least one heater positioned in at least two of the wellbores; and a self-regulating nuclear reactor configured to provide energy to at least one of the heaters to increase the temperature of at least a portion of the formation to temperatures that allow for hydrocarbon production from the formation; wherein heat input to at least a portion of the formation over time at least approximately correlates to a rate of decay of the power from the self-regulating nuclear reactor.
  • a method of producing hydrocarbons from a subsurface formation includes: forming a plurality of wellbores in the formation; positioning at least one heater in at least two of the wellbores; providing energy to at least one of the heaters to heat the temperature of the formation to temperatures that allow for hydrocarbon production from the formation using a self-regulating nuclear reactor; and at least approximately correlating heat input to at least a portion of the formation over time to a rate of decay of the power from the self-regulating nuclear reactor.
  • features from specific embodiments may be combined with features from other embodiments.
  • features from one embodiment may be combined with features from any of the other embodiments.
  • treating a subsurface formation is performed using any of the methods, systems, or heaters described herein.
  • FIG. 1 shows a schematic view of an embodiment of a portion of an in situ heat treatment system for treating a hydrocarbon containing formation.
  • FIG. 2 depicts a schematic representation of an embodiment of a system for treating a liquid stream produced from an in situ heat treatment process.
  • FIG. 3 depicts a schematic representation of an embodiment of a system for treating the mixture produced from an in situ heat treatment process.
  • FIG. 4 depicts a schematic representation of an embodiment of a system for forming and transporting tubing to a treatment area.
  • FIG. 5 depicts an embodiment of a drilling string with dual motors on a bottom hole assembly.
  • FIG. 6 depicts a schematic representation of an embodiment of a drilling string including a motor.
  • FIG. 7 depicts time versus rpm (revolutions per minute) for an embodiment of a conventional steerable motor bottom hole assembly during a drill bit direction change.
  • FIG. 8 depicts time versus rpm for an embodiment of a dual motor bottom hole assembly during a drill bit direction change.
  • FIG. 9 depicts an embodiment of a drilling string with a non-rotating sensor.
  • FIG. 10 depicts a schematic of an embodiment of a rack and pinion drilling system.
  • FIGS. 11A through 11D depict schematics of an embodiment for a continuous drilling sequence.
  • FIG. 12 depicts a cut-away view of an embodiment of a circulating sleeve of the bottom drive system depicted in FIGS. 11A-11D .
  • FIG. 13 depicts a schematic of the valve system of the circulating sleeve of the bottom drive system depicted in FIGS. 11A-11D .
  • FIG. 14 depicts a schematic of an embodiment of a first group of barrier wells used to form a first barrier and a second group of barrier wells used to form a second barrier.
  • FIGS. 15 , 16 , and 17 depict cross-sectional representations of an embodiment of a temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section.
  • FIGS. 18 , 19 , 20 , and 21 depict cross-sectional representations of an embodiment of a temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section placed inside a sheath.
  • FIGS. 22A and 22B depict cross-sectional representations of an embodiment of a temperature limited heater.
  • FIG. 23 depicts a cross-sectional representation of an embodiment of a composite conductor with a support member.
  • FIG. 24 depicts a cross-sectional representation of an embodiment of a composite conductor with a support member separating the conductors.
  • FIG. 25 depicts a cross-sectional representation of an embodiment of a composite conductor surrounding a support member.
  • FIG. 26 depicts a cross-sectional representation of an embodiment of a composite conductor surrounding a conduit support member.
  • FIG. 27 depicts a cross-sectional representation of an embodiment of a conductor-in-conduit heat source.
  • FIG. 28 depicts a cross-sectional representation of an embodiment of a removable conductor-in-conduit heat source.
  • FIG. 29 depicts a cross-sectional representation of an embodiment of a temperature limited heater in which the support member provides a majority of the heat output below the Curie temperature of the ferromagnetic conductor.
  • FIGS. 30 and 31 depict cross-sectional representations of embodiments of temperature limited heaters in which the jacket provides a majority of the heat output below the Curie temperature of the ferromagnetic conductor.
  • FIGS. 32A and 32B depict cross-sectional representations of an embodiment of a temperature limited heater component used in an insulated conductor heater.
  • FIG. 33 depicts a top view representation of three insulated conductors in a conduit.
  • FIG. 34 depicts an embodiment of three-phase wye transformer coupled to a plurality of heaters.
  • FIG. 35 depicts a side view representation of an embodiment of an end section of three insulated conductors in a conduit.
  • FIG. 36 depicts an embodiment of a heater with three insulated cores in a conduit.
  • FIG. 37 depicts an embodiment of a heater with three insulated conductors and an insulated return conductor in a conduit.
  • FIG. 38 depicts a side view cross-sectional representation of one embodiment of a fitting for joining insulated conductors.
  • FIG. 39 depicts an embodiment of a cutting tool.
  • FIG. 40 depicts a side view cross-sectional representation of another embodiment of a fitting for joining insulated conductors.
  • FIG. 41A depicts a side view of a cross-sectional representation of an embodiment of a threaded fitting for coupling three insulated conductors.
  • FIG. 41B depicts a side view of a cross-sectional representation of an embodiment of a welded fitting for coupling three insulated conductors.
  • FIG. 42 depicts an embodiment of a torque tool.
  • FIG. 43 depicts an embodiment of a clamp assembly that may be used to compact mechanically a fitting for joining insulated conductors.
  • FIG. 44 depicts an exploded view of an embodiment of a hydraulic compaction machine.
  • FIG. 45 depicts a representation of an embodiment of an assembled hydraulic compaction machine.
  • FIG. 46 depicts an embodiment of a fitting and insulated conductors secured in clamp assemblies before compaction of the fitting and insulated conductors.
  • FIG. 47 depicts a side view representation of yet another embodiment of a fitting for joining insulated conductors.
  • FIG. 48 depicts a side view representation of an embodiment of a fitting with an opening covered with an insert.
  • FIG. 49 depicts an embodiment of a fitting with electric field reducing features between the jackets of the insulated conductors and the sleeves and at the ends of the insulated conductors.
  • FIG. 50 depicts an embodiment of an electric field stress reducer.
  • FIG. 51 depicts an embodiment of an outer tubing partially unspooled from a coiled tubing rig.
  • FIG. 52 depicts an embodiment of a heater being pushed into outer tubing partially unspooled from a coiled tubing rig.
  • FIG. 53 depicts an embodiment of a heater being fully inserted into outer tubing with a drilling guide coupled to the end of the heater.
  • FIG. 54 depicts an embodiment of a heater, outer tubing, and drilling guide spooled onto a coiled tubing rig.
  • FIG. 55 depicts an embodiment of a coiled tubing rig being used to install a heater and outer tubing into an opening using a drilling guide.
  • FIG. 56 depicts an embodiment of a heater and outer tubing installed in an opening.
  • FIG. 57 depicts an embodiment of outer tubing being removed from an opening while leaving a heater installed in the opening.
  • FIG. 58 depicts an embodiment of outer tubing used to provide a packing material into an opening.
  • FIG. 59 depicts a schematic of an embodiment of outer tubing being spooled onto a coiled tubing rig after packing material is provided into an opening.
  • FIG. 60 depicts a schematic of an embodiment of outer tubing spooled onto a coiled tubing rig with a heater installed in an opening.
  • FIG. 61 depicts an embodiment of a heater installed in an opening with a wellhead.
  • FIG. 62 depicts a cross-sectional representation of an embodiment of an insulated conductor in a conduit with liquid between the insulated conductor and the conduit.
  • FIG. 63 depicts a cross-sectional representation of an embodiment of an insulated conductor heater in a conduit with a conductive liquid between the insulated conductor and the conduit.
  • FIG. 64 depicts a schematic representation of an embodiment of an insulated conductor in a conduit with liquid between the insulated conductor and the conduit, where a portion of the conduit and the insulated conductor are oriented horizontally in the formation.
  • FIG. 65 depicts a cross-sectional representation of an embodiment of a ribbed conduit.
  • FIG. 66 depicts a perspective representation of an embodiment of a portion of a ribbed conduit.
  • FIG. 67 depicts a cross-sectional representation an embodiment of a portion of an insulated conductor in a bottom portion of an open wellbore with a liquid between the insulated conductor and the formation.
  • FIG. 68 depicts a schematic cross-sectional representation of an embodiment of a portion of a formation with heat pipes positioned adjacent to a substantially horizontal portion of a heat source.
  • FIG. 69 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with the heat pipe located radially around an oxidizer assembly.
  • FIG. 70 depicts a cross-sectional representation of an angled heat pipe embodiment with an oxidizer assembly located near a lowermost portion of the heat pipe.
  • FIG. 71 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with an oxidizer located at the bottom of the heat pipe.
  • FIG. 72 depicts a cross-sectional representation of an angled heat pipe embodiment with an oxidizer located at the bottom of the heat pipe.
  • FIG. 73 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with an oxidizer that produces a flame zone adjacent to liquid heat transfer fluid in the bottom of the heat pipe.
  • FIG. 74 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with a tapered bottom that accommodates multiple oxidizers.
  • FIG. 75 depicts a cross-sectional representation of a heat pipe embodiment that is angled within the formation.
  • FIG. 76 depicts an embodiment of three heaters coupled in a three-phase configuration.
  • FIG. 77 depicts a side view representation of an embodiment of a substantially u-shaped three-phase heater in a formation.
  • FIG. 78 depicts a top view representation of an embodiment of a plurality of triads of three-phase heaters in a formation.
  • FIG. 79 depicts a top view representation of an embodiment of a plurality of triads of three-phase heaters in a formation with production wells.
  • FIG. 80 depicts a schematic of an embodiment of a heat treatment system that includes a heater and production wells.
  • FIG. 81 depicts a side view representation of one leg of a heater in the subsurface formation.
  • FIG. 82 depicts a schematic representation of an embodiment of a surface cabling configuration with a ground loop used for a heater and a production well.
  • FIG. 83 depicts a side view representation of an embodiment of an overburden portion of a conductor.
  • FIG. 84 depicts a side view representation of an embodiment of overburden portions of conductors grounded to a ground loop.
  • FIG. 85 depicts a side view representation of an embodiment of overburden portions of conductors with the conductors ungrounded.
  • FIG. 86 depicts a side view representation of an embodiment of overburden portions of conductors with the electrically conductive portions of casings lowered a selected depth below the surface.
  • FIG. 87 depicts a cross-sectional representation of an embodiment of a heater including nine single-phase flexible cable conductors positioned between tubulars.
  • FIG. 88 depicts a cross-sectional representation of an embodiment of a heater including nine single-phase flexible cable conductors positioned between tubulars with spacers.
  • FIG. 89 depicts a cross-sectional representation of an embodiment of a heater including nine multiple flexible cable conductors positioned between tubulars.
  • FIG. 90 depicts a cross-sectional representation of an embodiment of a heater including nine multiple flexible cable conductors positioned between tubulars with spacers.
  • FIG. 91 depicts an embodiment of a wellhead.
  • FIG. 92 depicts an example of a plot of dielectric constant versus temperature for magnesium oxide insulation in one embodiment of an insulated conductor heater.
  • FIG. 93 depicts an example of a plot of loss tangent (tan ⁇ ) versus temperature for magnesium oxide insulation in one embodiment of an insulated conductor heater.
  • FIG. 94 depicts an example of a plot of leakage current (mA) versus temperature (° F.) for magnesium oxide insulation in one embodiment of an insulated conductor heater at different applied voltages.
  • FIG. 95 depicts an embodiment of an insulated conductor with salt used as electrical insulator.
  • FIG. 96 depicts an embodiment of an insulated conductor located proximate heaters in a wellbore.
  • FIG. 97 depicts an embodiment of an insulated conductor with voltage applied to the core and the jacket of the insulated conductor.
  • FIG. 98 depicts an embodiment of an insulated conductor with multiple hot spots.
  • FIG. 99 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a relatively thin hydrocarbon layer.
  • FIG. 100 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that is thicker than the hydrocarbon layer depicted in FIG. 99 .
  • FIG. 101 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that is thicker than the hydrocarbon layer depicted in FIG. 100 .
  • FIG. 102 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that has a shale break.
  • FIG. 103 depicts a top view representation of an embodiment for preheating using heaters for the drive process.
  • FIG. 104 depicts a perspective representation of an embodiment for preheating using heaters for the drive process.
  • FIG. 105 depicts a side view representation of an embodiment of a tar sands formation subsequent to a steam injection process.
  • FIG. 106 depicts a side view representation of an embodiment using at least three treatment sections in a tar sands formation.
  • FIG. 107 depicts an embodiment for treating a formation with heaters in combination with one or more steam drive processes.
  • FIG. 108 depicts a comparison treating the formation using the embodiment depicted in FIG. 107 and treating the formation using the SAGD process.
  • FIG. 109 depicts an embodiment for heating and producing from a formation with a temperature limited heater in a production wellbore.
  • FIG. 110 depicts an embodiment for heating and producing from a formation with a temperature limited heater and a production wellbore.
  • FIG. 111 depicts a schematic of an embodiment of a first stage of treating a tar sands formation with electrical heaters.
  • FIG. 112 depicts a schematic of an embodiment of a second stage of treating the tar sands formation with fluid injection and oxidation.
  • FIG. 113 depicts a schematic of an embodiment of a third stage of treating the tar sands formation with fluid injection and oxidation.
  • FIG. 114 depicts a side view representation of a first stage of an embodiment of treating portions in a subsurface formation with heating, oxidation, and/or fluid injection.
  • FIG. 115 depicts a side view representation of a second stage of an embodiment of treating portions in the subsurface formation with heating, oxidation, and/or fluid injection.
  • FIG. 116 depicts a side view representation of a third stage of an embodiment of treating portions in subsurface formation with heating, oxidation and/or fluid injection.
  • FIG. 117 depicts an embodiment of treating a subsurface formation using a cylindrical pattern.
  • FIG. 118 depicts an embodiment of treating multiple portions of a subsurface formation in a rectangular pattern.
  • FIG. 119 is a schematic top view of the pattern depicted in FIG. 118 .
  • FIG. 120 depicts a cross-sectional representation of an embodiment of substantially horizontal heaters positioned in a pattern with consistent spacing in a hydrocarbon layer.
  • FIG. 121 depicts a cross-sectional representation of an embodiment of substantially horizontal heaters positioned in a pattern with irregular spacing in a hydrocarbon layer.
  • FIG. 122 depicts a graphical representation of a comparison of the temperature and the pressure over time for two different portions of the formation using the different heating patterns.
  • FIG. 123 depicts a graphical representation of a comparison of the average temperature over time for different treatment areas for two different portions of the formation using the different heating patterns.
  • FIG. 124 depicts a graphical representation of the bottom-hole pressures for several producer wells for two different heating patterns.
  • FIG. 125 depicts a graphical representation of a comparison of the cumulative oil and gas products extracted over time from two different portions of the formation using the different heating patterns.
  • FIG. 126 depicts a cross-sectional representation of another embodiment of substantially horizontal heaters positioned in a pattern with irregular spacing in a hydrocarbon layer.
  • FIG. 127 depicts a cross-sectional representation of another embodiment of substantially horizontal heaters positioned in a pattern with irregular spacing in a hydrocarbon layer.
  • FIG. 128 depicts a cross-sectional representation of another additional embodiment of substantially horizontal heaters positioned in a pattern with irregular spacing in a hydrocarbon layer.
  • FIG. 129 depicts a cross-sectional representation of another embodiment of substantially horizontal heaters positioned in a pattern with consistent spacing in a hydrocarbon layer.
  • FIG. 130 depicts a cross-sectional representation of an embodiment of substantially horizontal heaters positioned in a pattern with irregular spacing in a hydrocarbon layer, with three rows of heaters in three heating zones.
  • FIG. 131 depicts a schematic representation of an embodiment of a system for producing oxygen for use in downhole oxidizer assemblies.
  • FIG. 132 depicts an embodiment of a heater with a heating section located in a u-shaped wellbore to create a first heated volume.
  • FIG. 133 depicts an embodiment of a heater with a heating section located in a u-shaped wellbore to create a second heated volume.
  • FIG. 134 depicts an embodiment of a heater with a heating section located in a u-shaped wellbore to create a third heated volume.
  • FIG. 135 depicts an embodiment of a heater with a heating section located in an L-shaped or J-shaped wellbore to create a first heated volume.
  • FIG. 136 depicts an embodiment of a heater with a heating section located in an L-shaped or J-shaped wellbore to create a second heated volume.
  • FIG. 137 depicts an embodiment of a heater with a heating section located in an L-shaped or J-shaped wellbore to create a third heated volume.
  • FIG. 138 depicts an embodiment of two heaters with heating sections located in a u-shaped wellbore to create two heated volumes.
  • FIG. 139 depicts a top view of a treatment area treated using non-overlapping heating sections in heaters.
  • FIG. 140 depicts a top view of a treatment area treated using overlapping heating sections in the first phase of heating using heaters.
  • FIG. 141 depicts a schematic representation of an embodiment of a heat transfer fluid circulation system for heating a portion of a formation.
  • FIG. 142 depicts a schematic representation of an embodiment of an L-shaped heater for use with a heat transfer fluid circulation system for heating a portion of a formation.
  • FIG. 143 depicts a schematic representation of an embodiment of a vertical heater for use with a heat transfer fluid circulation system for heating a portion of a formation where thermal expansion of the heater is accommodated below the surface.
  • FIG. 144 depicts a schematic representation of another embodiment of a vertical heater for use with a heat transfer fluid circulation system for heating a portion of a formation where thermal expansion of the heater is accommodated above and below the surface.
  • FIG. 145 depicts a schematic representation of a corridor pattern system used to treat a treatment area.
  • FIG. 146 depicts a schematic representation of a radial pattern system used to a treat treatment area.
  • FIG. 147 depicts a plan view of an embodiment of wellbore openings on a first side of a treatment area.
  • FIG. 148 depicts a cross-sectional view of an embodiment of overburden insulation that utilizes insulating cement.
  • FIG. 149 depicts a cross-sectional view of an embodiment of overburden insulation that utilizes an insulating sleeve.
  • FIG. 150 depicts a cross-sectional view of an embodiment of overburden insulation that utilizes an insulating sleeve and a vacuum.
  • FIG. 151 depicts a representation an embodiment of bellows used to accommodate thermal expansion.
  • FIG. 152A depicts a representation of an embodiment of piping with an expansion loop for accommodating thermal expansion.
  • FIG. 152B depicts a representation of an embodiment of piping with coiled or spooled piping for accommodating thermal expansion.
  • FIG. 152C depicts a representation of an embodiment of piping with coiled or spooled piping for accommodating thermal expansion enclosed in an insulated volume.
  • FIG. 153 depicts a representation of an embodiment of insulated piping in a large diameter casing in the overburden.
  • FIG. 154 depicts a representation of an embodiment of insulated piping in a large diameter casing in the overburden to accommodate thermal expansion.
  • FIG. 155 depicts a representation of an embodiment of a wellhead with a sliding seal, stuffing box, or other pressure control equipment that allows a portion of a heater to move relative to the wellhead.
  • FIG. 156 depicts a representation of an embodiment of a wellhead with a slip joint that interacts with a fixed conduit above the wellhead.
  • FIG. 157 depicts a representation of an embodiment of a wellhead with a slip joint that interacts with a fixed conduit coupled to the wellhead.
  • FIG. 158 depicts a schematic representation of an embodiment a heat transfer fluid circulating system with seals.
  • FIG. 159 depicts a schematic representation of another embodiment a heat transfer fluid circulating system with seals.
  • FIG. 160 depicts a schematic representation an embodiment a heat transfer fluid circulating system with locking mechanisms and seals.
  • FIG. 161 depicts a representation of a u-shaped wellbore with a hot heat transfer fluid circulation system heater positioned in the wellbore.
  • FIG. 162 depicts a side view representation of an embodiment of a system for heating the formation that can use a closed loop circulation system and/or electrical heating.
  • FIG. 163 depicts a representation of a heat transfer fluid conduit that may initially be resistively heated with the return current path provided by an insulated conductor.
  • FIG. 164 depicts a representation of a heat transfer fluid conduit that may initially be resistively heated with the return current path provided by two insulated conductors.
  • FIG. 165 depicts a representation of insulated conductors used to resistively heat heaters of a circulated fluid heating system.
  • FIG. 166 depicts an end view representation of a heater of a heat transfer fluid circulation system with an insulated conductor heater positioned in the piping.
  • FIG. 167 depicts an end view representation of an embodiment of a conduit-in-conduit heater for a heat transfer circulation heating system adjacent to the treatment area.
  • FIG. 168 depicts a representation of an embodiment for heating various portions of a heater to restart flow of heat transfer fluid in the heater.
  • FIG. 169 depicts a schematic of an embodiment of conduit-in-conduit heaters of a fluid circulation heating system positioned in the formation.
  • FIG. 170 depicts a cross-sectional view of an embodiment of a conduit-in-conduit heater adjacent to the overburden.
  • FIG. 171 depicts a schematic representation of an embodiment of a circulation system for a liquid heat transfer fluid.
  • FIG. 172 depicts a schematic representation of an embodiment of a system for heating the formation using gas lift to return the heat transfer fluid to the surface.
  • FIG. 173 depicts an end view representation of an embodiment of a wellbore in a treatment area undergoing a combustion process.
  • FIG. 174 depicts an end view representation of an embodiment of a wellbore in a treatment area undergoing fluid removal following the combustion process.
  • FIG. 175 depicts an end view representation of an embodiment of a wellbore in a treatment area undergoing a combustion process using circulated molten salt to recover energy from the treatment area.
  • FIG. 176 depicts percentage of the expected coke distribution relative to a distance from a wellbore.
  • FIG. 177 depicts a schematic representation of an embodiment of an in situ heat treatment system that uses a nuclear reactor.
  • FIG. 178 depicts an elevational view of an embodiment of an in situ heat treatment system using pebble bed reactors.
  • FIG. 179 depicts a schematic representation of an embodiment of a self-regulating nuclear reactor.
  • FIG. 180 depicts a schematic representation of an embodiment of an in situ heat treatment system with u-shaped wellbores using self-regulating nuclear reactors.
  • FIG. 181 depicts a side view representation of an embodiment for producing mobilized fluids from a hydrocarbon formation.
  • FIG. 182 depicts a side view representation of an embodiment for producing mobilized fluids from a hydrocarbon formation heated by residual heat.
  • FIG. 183 depicts an embodiment of a solution mining well.
  • FIG. 184 depicts a representation of an embodiment of a portion of a solution mining well.
  • FIG. 185 depicts a representation of another embodiment of a portion of a solution mining well.
  • FIG. 186 depicts an elevational view of a well pattern for solution mining and/or an in situ heat treatment process.
  • FIG. 187 depicts a representation of wells of an in situ heating treatment process for solution mining and producing hydrocarbons from a formation.
  • FIG. 188 depicts an embodiment for solution mining a formation.
  • FIG. 189 depicts an embodiment of a formation with nahcolite layers in the formation before solution mining nahcolite from the formation.
  • FIG. 190 depicts the formation of FIG. 189 after the nahcolite has been solution mined
  • FIG. 191 depicts an embodiment of two injection wells interconnected by a zone that has been solution mined to remove nahcolite from the zone.
  • FIG. 192 depicts a representation of an embodiment for treating a portion of a formation having a hydrocarbon containing formation between an upper nahcolite bed and a lower nahcolite bed.
  • FIG. 193 depicts a representation of a portion of the formation that is orthogonal to the formation depicted in FIG. 192 and passes through one of the solution mining wells in the upper nahcolite bed.
  • FIG. 194 depicts an embodiment for heating a formation with dawsonite in the formation.
  • FIG. 195 depicts a representation of an embodiment for solution mining with a steam and electricity cogeneration facility.
  • FIG. 196 depicts an embodiment of treating a hydrocarbon containing formation with a combustion front.
  • FIG. 197 depicts a cross-sectional representation of an embodiment for treating a hydrocarbon containing formation with a combustion front.
  • FIG. 198 depicts a schematic representation of an embodiment of a circulated fluid cooling system.
  • FIG. 199 depicts a schematic of an embodiment for treating a subsurface formation using heat sources having electrically conductive material.
  • FIG. 200 depicts a schematic of an embodiment for treating a subsurface formation using a ground and heat sources having electrically conductive material.
  • FIG. 201 depicts a schematic of an embodiment for treating a subsurface formation using heat sources having electrically conductive material and an electrical insulator.
  • FIG. 202 depicts a schematic of an embodiment for treating a subsurface formation using electrically conductive heat sources extending from a common wellbore.
  • FIG. 203 depicts a schematic of an embodiment for treating a subsurface formation having a shale layer using heat sources having electrically conductive material.
  • FIG. 204A depicts a schematic of an embodiment of an electrode with a coated end.
  • FIG. 204B depicts a schematic of an embodiment of an uncoated electrode.
  • FIG. 205A depicts a schematic of another embodiment of a coated electrode.
  • FIG. 205B depicts a schematic of another embodiment of an uncoated electrode.
  • FIG. 206 depicts a perspective view of an embodiment of an underground treatment system.
  • FIG. 207 depicts an exploded perspective view of an embodiment of a portion of an underground treatment system and tunnels.
  • FIG. 208 depicts another exploded perspective view of an embodiment of a portion of an underground treatment system and tunnels.
  • FIG. 209 depicts a side view representation of an embodiment for flowing heated fluid through heat sources between tunnels.
  • FIG. 210 depicts a top view representation of an embodiment for flowing heated fluid through heat sources between tunnels.
  • FIG. 211 depicts a perspective view of an embodiment of an underground treatment system having heater wellbores spanning between tunnels of the underground treatment system.
  • FIG. 212 depicts a top view of an embodiment of tunnels with wellbore chambers.
  • FIG. 213 depicts a top view of an embodiment of development of a tunnel.
  • FIG. 214 depicts a schematic of an embodiment of an underground treatment system with surface production.
  • FIG. 215 depicts a side view of an embodiment of an underground treatment system.
  • FIG. 216 depicts a temperature profile in the formation after 360 days using the STARS simulation.
  • FIG. 217 depicts an oil saturation profile in the formation after 360 days using the STARS simulation.
  • FIG. 218 depicts the oil saturation profile in the formation after 1095 days using the STARS simulation.
  • FIG. 219 depicts the oil saturation profile in the formation after 1470 days using the STARS simulation.
  • FIG. 220 depicts the oil saturation profile in the formation after 1826 days using the STARS simulation.
  • FIG. 221 depicts the temperature profile in the formation after 1826 days using the STARS simulation.
  • FIG. 222 depicts oil production rate and gas production rate versus time.
  • FIG. 223 depicts weight percentage of original bitumen in place (OBIP)(left axis) and volume percentage of OBIP (right axis) versus temperature (° C.).
  • FIG. 224 depicts bitumen conversion percentage (weight percentage of (OBIP))(left axis) and oil, gas, and coke weight percentage (as a weight percentage of OBIP)(right axis) versus temperature (° C.).
  • FIG. 225 depicts API gravity)(°)(left axis) of produced fluids, blow down production, and oil left in place along with pressure (psig)(right axis) versus temperature (° C.).
  • FIGS. 226A-D depict gas-to-oil ratios (GOR) in thousand cubic feet per barrel ((Mcf/bbl)(y-axis)) versus temperature (° C.)(x-axis) for different types of gas at a low temperature blow down (about 277° C.) and a high temperature blow down (at about 290° C.).
  • GOR gas-to-oil ratios
  • FIG. 227 depicts coke yield (weight percentage)(y-axis) versus temperature (° C.)(x-axis).
  • FIGS. 228A-D depict assessed hydrocarbon isomer shifts in fluids produced from the experimental cells as a function of temperature and bitumen conversion.
  • FIG. 229 depicts weight percentage (Wt %)(y-axis) of saturates from SARA analysis of the produced fluids versus temperature (° C.)(x-axis).
  • FIG. 230 depicts weight percentage (Wt %)(y-axis) of n-C 7 of the produced fluids versus temperature (° C.)(x-axis).
  • FIG. 231 depicts oil recovery (volume percentage bitumen in place (vol % BIP)) versus API gravity)(° as determined by the pressure (MPa) in the formation in an experiment.
  • FIG. 232 depicts recovery efficiency (%) versus temperature (° C.) at different pressures in an experiment.
  • FIG. 233 depicts average formation temperature (° C.) versus days for heating a formation using molten salt circulated through conduit-in-conduit heaters.
  • FIG. 234 depicts molten salt temperature (° C.) and power injection rate (W/ft) versus time (days).
  • FIG. 235 depicts temperature (° C.) and power injection rate (W/ft) versus time (days) for heating a formation using molten salt circulated through heaters with a heating length of 8000 ft at a mass flow rate of 18 kg/s.
  • FIG. 236 depicts temperature (° C.) and power injection rate (W/ft) versus time (days) for heating a formation using molten salt circulated through heaters with a heating length of 8000 ft at a mass flow rate of 12 kg/s.
  • FIG. 237 depicts power (W/ft)(y-axis) versus time (yr)(x-axis) of in situ heat treatment power injection requirements.
  • FIG. 238 depicts power (W/ft)(y-axis) versus time (days)(x-axis) of in situ heat treatment power injection requirements for different spacings between wellbores.
  • FIG. 239 depicts reservoir average temperature (° C.)(y-axis) versus time (days)(x-axis) of in situ heat treatment for different spacings between wellbores.
  • FIG. 240 depicts time (hour) versus temperature (° C.) and molten salt concentration in weight percent.
  • FIG. 241 depicts heat transfer rates versus time.
  • FIG. 242 depicts percentage of degree of saturation (volume water/air voids) versus time during immersion at a water temperature of 60° C.
  • FIG. 243 depicts retained indirect tensile strength stiffness modulus versus time during immersion at a water temperature of 60° C.
  • the following description generally relates to systems and methods for treating hydrocarbons in the formations. Such formations may be treated to yield hydrocarbon products, hydrogen, and other products.
  • Alternating current refers to a time-varying current that reverses direction substantially sinusoidally. AC produces skin effect electricity flow in a ferromagnetic conductor.
  • Annular region is the region between an outer conduit and an inner conduit positioned in the outer conduit.
  • API gravity refers to API gravity at 15.5° C. (60° F.). API gravity is as determined by ASTM Method D6822 or ASTM Method D1298.
  • ASTM refers to American Standard Testing and Materials.
  • the term “automatically” means such systems, apparatus, and methods function in a certain way without the use of external control (for example, external controllers such as a controller with a temperature sensor and a feedback loop, PID controller, or predictive controller).
  • external controllers such as a controller with a temperature sensor and a feedback loop, PID controller, or predictive controller.
  • Asphalt/bitumen refers to a semi-solid, viscous material soluble in carbon disulfide. Asphalt/bitumen may be obtained from refining operations or produced from subsurface formations.
  • “Bare metal” and “exposed metal” refer to metals of elongated members that do not include a layer of electrical insulation, such as mineral insulation, that is designed to provide electrical insulation for the metal throughout an operating temperature range of the elongated member.
  • Bare metal and exposed metal may encompass a metal that includes a corrosion inhibiter such as a naturally occurring oxidation layer, an applied oxidation layer, and/or a film.
  • Bare metal and exposed metal include metals with polymeric or other types of electrical insulation that cannot retain electrical insulating properties at typical operating temperature of the elongated member. Such material may be placed on the metal and may be thermally degraded during use of the heater.
  • Boiling range distributions for the formation fluid and liquid streams described herein are as determined by ASTM Method D5307 or ASTM Method D2887. Content of hydrocarbon components in weight percent for paraffins, iso-paraffins, olefins, naphthenes and aromatics in the liquid streams is as determined by ASTM Method D6730. Content of aromatics in volume percent is as determined by ASTM Method D1319. Weight percent of hydrogen in hydrocarbons is as determined by ASTM Method D3343.
  • Bromine number refers to a weight percentage of olefins in grams per 100 gram of portion of the produced fluid that has a boiling range below 246° C. and testing the portion using ASTM Method D 1159 .
  • Carbon number refers to the number of carbon atoms in a molecule.
  • a hydrocarbon fluid may include various hydrocarbons with different carbon numbers.
  • the hydrocarbon fluid may be described by a carbon number distribution.
  • Carbon numbers and/or carbon number distributions may be determined by true boiling point distribution and/or gas-liquid chromatography.
  • “Chemically stability” refers to the ability of a formation fluid to be transported without components in the formation fluid reacting to form polymers and/or compositions that plug pipelines, valves, and/or vessels.
  • “Clogging” refers to impeding and/or inhibiting flow of one or more compositions through a process vessel or a conduit.
  • Column X element or “Column X elements” refer to one or more elements of Column X of the Periodic Table, and/or one or more compounds of one or more elements of Column X of the Periodic Table, in which X corresponds to a column number (for example, 13-18) of the Periodic Table.
  • Column 15 elements refer to elements from Column 15 of the Periodic Table and/or compounds of one or more elements from Column 15 of the Periodic Table.
  • Column X metal or “Column X metals” refer to one or more metals of Column X of the Periodic Table and/or one or more compounds of one or more metals of Column X of the Periodic Table, in which X corresponds to a column number (for example, 1-12) of the Periodic Table.
  • Column 6 metals refer to metals from Column 6 of the Periodic Table and/or compounds of one or more metals from Column 6 of the Periodic Table.
  • Condensable hydrocarbons are hydrocarbons that condense at 25° C. and one atmosphere absolute pressure. Condensable hydrocarbons may include a mixture of hydrocarbons having carbon numbers greater than 4. “Non-condensable hydrocarbons” are hydrocarbons that do not condense at 25° C. and one atmosphere absolute pressure. Non-condensable hydrocarbons may include hydrocarbons having carbon numbers less than 5.
  • Coring is a process that generally includes drilling a hole into a formation and removing a substantially solid mass of the formation from the hole.
  • “Cracking” refers to a process involving decomposition and molecular recombination of organic compounds to produce a greater number of molecules than were initially present. In cracking, a series of reactions take place accompanied by a transfer of hydrogen atoms between molecules. For example, naphtha may undergo a thermal cracking reaction to form ethene and H 2 .
  • “Curie temperature” is the temperature above which a ferromagnetic material loses all of its ferromagnetic properties. In addition to losing all of its ferromagnetic properties above the Curie temperature, the ferromagnetic material begins to lose its ferromagnetic properties when an increasing electrical current is passed through the ferromagnetic material.
  • Diad refers to a group of two items (for example, heaters, wellbores, or other objects) coupled together.
  • Diesel refers to hydrocarbons with a boiling range distribution between 260° C. and 343° C. (500-650° F.) at 0.101 MPa. Diesel content is determined by ASTM Method D2887.
  • Enriched air refers to air having a larger mole fraction of oxygen than air in the atmosphere. Air is typically enriched to increase combustion-supporting ability of the air.
  • a “fluid” may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.
  • Fluid injectivity is the flow rate of fluids injected per unit of pressure differential between a first location and a second location.
  • Fluid pressure is a pressure generated by a fluid in a formation.
  • Low density pressure (sometimes referred to as “lithostatic stress”) is a pressure in a formation equal to a weight per unit area of an overlying rock mass.
  • Hydrostatic pressure is a pressure in a formation exerted by a column of water.
  • a “formation” includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden.
  • Hydrocarbon layers refer to layers in the formation that contain hydrocarbons.
  • the hydrocarbon layers may contain non-hydrocarbon material and hydrocarbon material.
  • the “overburden” and/or the “underburden” include one or more different types of impermeable materials.
  • the overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate.
  • the overburden and/or the underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ heat treatment processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or the underburden.
  • the underburden may contain shale or mudstone, but the underburden is not allowed to heat to pyrolysis temperatures during the in situ heat treatment process.
  • the overburden and/or the underburden may be somewhat permeable.
  • Formation fluids refer to fluids present in a formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbons, and water (steam). Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids.
  • the term “mobilized fluid” refers to fluids in a hydrocarbon containing formation that are able to flow as a result of thermal treatment of the formation.
  • Produced fluids refer to fluids removed from the formation.
  • Freezing point of a hydrocarbon liquid refers to the temperature below which solid hydrocarbon crystals may form in the liquid. Freezing point is as determined by ASTM Method D5901.
  • Heat flux is a flow of energy per unit of area per unit of time (for example, Watts/meter 2 ).
  • a “heat source” is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer.
  • a heat source may include electrically conducting materials and/or electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed in a conduit.
  • a heat source may also include systems that generate heat by burning a fuel external to or in a formation. The systems may be surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors.
  • heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer medium that directly or indirectly heats the formation.
  • one or more heat sources that are applying heat to a formation may use different sources of energy.
  • some heat sources may supply heat from electrically conducting materials, electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (for example, chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy).
  • a chemical reaction may include an exothermic reaction (for example, an oxidation reaction).
  • a heat source may also include a electrically conducting material and/or a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.
  • a “heater” is any system or heat source for generating heat in a well or a near wellbore region.
  • Heaters may be, but are not limited to, electric heaters, burners, combustors that react with material in or produced from a formation, and/or combinations thereof.
  • Heavy hydrocarbons are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, and nitrogen. Additional elements may also be present in heavy hydrocarbons in trace amounts. Heavy hydrocarbons may be classified by API gravity. Heavy hydrocarbons generally have an API gravity below about 20°. Heavy oil, for example, generally has an API gravity of about 10-20°, whereas tar generally has an API gravity below about 10°. The viscosity of heavy hydrocarbons is generally greater than about 100 centipoise at 15° C. Heavy hydrocarbons may include aromatics or other complex ring hydrocarbons.
  • Heavy hydrocarbons may be found in a relatively permeable formation.
  • the relatively permeable formation may include heavy hydrocarbons entrained in, for example, sand or carbonate.
  • “Relatively permeable” is defined, with respect to formations or portions thereof, as an average permeability of 10 millidarcy or more (for example, 10 or 100 millidarcy).
  • “Relatively low permeability” is defined, with respect to formations or portions thereof, as an average permeability of less than about 10 millidarcy.
  • One darcy is equal to about 0.99 square micrometers.
  • An impermeable layer generally has a permeability of less than about 0.1 millidarcy.
  • Certain types of formations that include heavy hydrocarbons may also include, but are not limited to, natural mineral waxes, or natural asphaltites.
  • Natural mineral waxes typically occur in substantially tubular veins that may be several meters wide, several kilometers long, and hundreds of meters deep.
  • Natural asphaltites include solid hydrocarbons of an aromatic composition and typically occur in large veins.
  • In situ recovery of hydrocarbons from formations such as natural mineral waxes and natural asphaltites may include melting to form liquid hydrocarbons and/or solution mining of hydrocarbons from the formations.
  • Hydrocarbons are generally defined as molecules formed primarily by carbon and hydrogen atoms. Hydrocarbons may also include other elements such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located in or adjacent to mineral matrices in the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. “Hydrocarbon fluids” are fluids that include hydrocarbons. Hydrocarbon fluids may include, entrain, or be entrained in non-hydrocarbon fluids such as hydrogen, nitrogen, carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.
  • An “in situ conversion process” refers to a process of heating a hydrocarbon containing formation from heat sources to raise the temperature of at least a portion of the formation above a pyrolysis temperature so that pyrolyzation fluid is produced in the formation.
  • An “in situ heat treatment process” refers to a process of heating a hydrocarbon containing formation with heat sources to raise the temperature of at least a portion of the formation above a temperature that results in mobilized fluid, visbreaking, and/or pyrolysis of hydrocarbon containing material so that mobilized fluids, visbroken fluids, and/or pyrolyzation fluids are produced in the formation.
  • Insulated conductor refers to any elongated material that is able to conduct electricity and that is covered, in whole or in part, by an electrically insulating material.
  • “Karst” is a subsurface shaped by the dissolution of a soluble layer or layers of bedrock, usually carbonate rock such as limestone or dolomite.
  • the dissolution may be caused by meteoric or acidic water.
  • the Grosmont formation in Alberta, Canada is an example of a karst (or “karsted”) carbonate formation.
  • Kerogen is a solid, insoluble hydrocarbon that has been converted by natural degradation and that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples of materials that contain kerogen.
  • Biten is a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide.
  • Oil is a fluid containing a mixture of condensable hydrocarbons.
  • Kerosene refers to hydrocarbons with a boiling range distribution between 204° C. and 260° C. at 0.101 MPa. Kerosene content is determined by ASTM Method D2887.
  • Modulated direct current refers to any substantially non-sinusoidal time-varying current that produces skin effect electricity flow in a ferromagnetic conductor.
  • Naphtha refers to hydrocarbon components with a boiling range distribution between 38° C. and 200° C. at 0.101 MPa. Naphtha content is determined by ASTM Method D5307.
  • Nitride refers to a compound of nitrogen and one or more other elements of the Periodic Table. Nitrides include, but are not limited to, silicon nitride, boron nitride, or alumina nitride.
  • Nitrogen compound content refers to an amount of nitrogen in an organic compound. Nitrogen content is as determined by ASTM Method D5762.
  • Optane Number refers to a calculated numerical representation of the antiknock properties of a motor fuel compared to a standard reference fuel. A calculated octane number is determined by ASTM Method D6730.
  • Olefins are molecules that include unsaturated hydrocarbons having one or more non-aromatic carbon-carbon double bonds.
  • Olefin content refers to an amount of non-aromatic olefins in a fluid. Olefin content for a produced fluid is determined by obtaining a portion of the produce fluid that has a boiling point of 246° C. and testing the portion using ASTM Method D1159 and reporting the result as a bromine factor in grams per 100 gram of portion. Olefin content is also determined by the Canadian Association of Petroleum Producers (CAPP) olefin method and is reported in percent olefin as 1-decene equivalent.
  • CAPP Canadian Association of Petroleum Producers
  • Organonitrogen compounds refer to hydrocarbons that contain at least one nitrogen atom.
  • organonitrogen compounds include, but are not limited to, alkyl amines, aromatic amines, alkyl amides, aromatic amides, pyridines, pyrazoles, and oxazoles.
  • Openings refer to openings, such as openings in conduits, having a wide variety of sizes and cross-sectional shapes including, but not limited to, circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes.
  • P (peptization) value or “P-value” refers to a numerical value, which represents the flocculation tendency of asphaltenes in a formation fluid. P-value is determined by ASTM method D7060.
  • Perforations include openings, slits, apertures, or holes in a wall of a conduit, tubular, pipe or other flow pathway that allow flow into or out of the conduit, tubular, pipe or other flow pathway.
  • Periodic Table refers to the Periodic Table as specified by the International Union of Pure and Applied Chemistry (IUPAC), November 2003.
  • weight of a metal from the Periodic Table, weight of a compound of a metal from the Periodic Table, weight of an element from the Periodic Table, or weight of a compound of an element from the Periodic Table is calculated as the weight of metal or the weight of element. For example, if 0.1 grams of MoO 3 is used per gram of catalyst, the calculated weight of the molybdenum metal in the catalyst is 0.067 grams per gram of catalyst.
  • Phase transformation temperature of a ferromagnetic material refers to a temperature or a temperature range during which the material undergoes a phase change (for example, from ferrite to austenite) that decreases the magnetic permeability of the ferromagnetic material.
  • the reduction in magnetic permeability is similar to reduction in magnetic permeability due to the magnetic transition of the ferromagnetic material at the Curie temperature.
  • Physical stability refers to the ability of a formation fluid to not exhibit phase separation or flocculation during transportation of the fluid. Physical stability is determined by ASTM Method D7060.
  • Pyrolysis is the breaking of chemical bonds due to the application of heat.
  • pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.
  • “Pyrolyzation fluids” or “pyrolysis products” refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product.
  • “pyrolysis zone” refers to a volume of a formation (for example, a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.
  • Residue refers to hydrocarbons that have a boiling point above 537° C. (1000° F.).
  • “Rich layers” in a hydrocarbon containing formation are relatively thin layers (typically about 0.2 m to about 0.5 m thick). Rich layers generally have a richness of about 0.150 L/kg or greater. Some rich layers have a richness of about 0.170 L/kg or greater, of about 0.190 L/kg or greater, or of about 0.210 L/kg or greater. Lean layers of the formation have a richness of about 0.100 L/kg or less and are generally thicker than rich layers. The richness and locations of layers are determined, for example, by coring and subsequent Fischer assay of the core, density or neutron logging, or other logging methods. Rich layers may have a lower initial thermal conductivity than other layers of the formation. Typically, rich layers have a thermal conductivity 1.5 times to 3 times lower than the thermal conductivity of lean layers. In addition, rich layers have a higher thermal expansion coefficient than lean layers of the formation.
  • Smart well technology or “smart wellbore” refers to wells that incorporate downhole measurement and/or control.
  • smart well technology may allow for controlled injection of fluid into the formation in desired zones.
  • smart well technology may allow for controlled production of formation fluid from selected zones.
  • Some wells may include smart well technology that allows for formation fluid production from selected zones and simultaneous or staggered solution injection into other zones.
  • Smart well technology may include fiber optic systems and control valves in the wellbore.
  • a smart wellbore used for an in situ heat treatment process may be Westbay Multilevel Well System MP55 available from Westbay Instruments Inc. (Burnaby, British Columbia, Canada).
  • Subsidence is a downward movement of a portion of a formation relative to an initial elevation of the surface.
  • Sulfur compound content refers to an amount of sulfur in an organic compound. Sulfur content is as determined by ASTM Method D4294.
  • Superposition of heat refers to providing heat from two or more heat sources to a selected section of a formation such that the temperature of the formation at least at one location between the heat sources is influenced by the heat sources.
  • Synthesis gas is a mixture including hydrogen and carbon monoxide. Additional components of synthesis gas may include water, carbon dioxide, nitrogen, methane, and other gases. Synthesis gas may be generated by a variety of processes and feedstocks. Synthesis gas may be used for synthesizing a wide range of compounds.
  • TAN refers to a total acid number expressed as milligrams (“mg”) of KOH per gram (“g”) of sample. TAN is as determined by ASTM Method D3242.
  • “Tar” is a viscous hydrocarbon that generally has a viscosity greater than about 10,000 centipoise at 15° C.
  • the specific gravity of tar generally is greater than 1.000.
  • Tar may have an API gravity less than 10°.
  • a “tar sands formation” is a formation in which hydrocarbons are predominantly present in the form of heavy hydrocarbons and/or tar entrained in a mineral grain framework or other host lithology (for example, sand or carbonate).
  • Examples of tar sands formations include formations such as the Athabasca formation, the Grosmont formation, and the Peace River formation, all three in Alberta, Canada; and the Faja formation in the Orinoco belt in Venezuela.
  • Temperature limited heater generally refers to a heater that regulates heat output (for example, reduces heat output) above a specified temperature without the use of external controls such as temperature controllers, power regulators, rectifiers, or other devices. Temperature limited heaters may be AC (alternating current) or modulated (for example, “chopped”) DC (direct current) powered electrical resistance heaters.
  • “Thermally conductive fluid” includes fluid that has a higher thermal conductivity than air at standard temperature and pressure (STP) (0° C. and 101.325 kPa).
  • Thermal conductivity is a property of a material that describes the rate at which heat flows, in steady state, between two surfaces of the material for a given temperature difference between the two surfaces.
  • Thermal fracture refers to fractures created in a formation caused by expansion or contraction of a formation and/or fluids in the formation, which is in turn caused by increasing/decreasing the temperature of the formation and/or fluids in the formation, and/or by increasing/decreasing a pressure of fluids in the formation due to heating.
  • Thermal oxidation stability refers to thermal oxidation stability of a liquid. Thermal oxidation stability is as determined by ASTM Method D3241.
  • Thickness of a layer refers to the thickness of a cross section of the layer, wherein the cross section is normal to a face of the layer.
  • Time-varying current refers to electrical current that produces skin effect electricity flow in a ferromagnetic conductor and has a magnitude that varies with time. Time-varying current includes both alternating current (AC) and modulated direct current (DC).
  • AC alternating current
  • DC modulated direct current
  • Triad refers to a group of three items (for example, heaters, wellbores, or other objects) coupled together.
  • “Turndown ratio” for the temperature limited heater in which current is applied directly to the heater is the ratio of the highest AC or modulated DC resistance below the Curie temperature to the lowest resistance above the Curie temperature for a given current.
  • Turndown ratio for an inductive heater is the ratio of the highest heat output below the Curie temperature to the lowest heat output above the Curie temperature for a given current applied to the heater.
  • a “u-shaped wellbore” refers to a wellbore that extends from a first opening in the formation, through at least a portion of the formation, and out through a second opening in the formation.
  • the wellbore may be only roughly in the shape of a “v” or “u”, with the understanding that the “legs” of the “u” do not need to be parallel to each other, or perpendicular to the “bottom” of the “u” for the wellbore to be considered “u-shaped”.
  • “Upgrade” refers to increasing the quality of hydrocarbons. For example, upgrading heavy hydrocarbons may result in an increase in the API gravity of the heavy hydrocarbons.
  • “Visbreaking” refers to the untangling of molecules in fluid during heat treatment and/or to the breaking of large molecules into smaller molecules during heat treatment, which results in a reduction of the viscosity of the fluid.
  • Viscosity refers to kinematic viscosity at 40° C. unless otherwise specified. Viscosity is as determined by ASTM Method D445.
  • VGO or “vacuum gas oil” refers to hydrocarbons with a boiling range distribution between 343° C. and 538° C. at 0.101 MPa. VGO content is determined by ASTM Method D5307.
  • a “vug” is a cavity, void or large pore in a rock that is commonly lined with mineral precipitates.
  • Wax refers to a low melting organic mixture, or a compound of high molecular weight that is a solid at lower temperatures and a liquid at higher temperatures, and when in solid form can form a barrier to water.
  • waxes include animal waxes, vegetable waxes, mineral waxes, petroleum waxes, and synthetic waxes.
  • wellbore refers to a hole in a formation made by drilling or insertion of a conduit into the formation.
  • a wellbore may have a substantially circular cross section, or another cross-sectional shape.
  • wellbore and opening when referring to an opening in the formation may be used interchangeably with the term “wellbore.”
  • a formation may be treated in various ways to produce many different products. Different stages or processes may be used to treat the formation during an in situ heat treatment process.
  • one or more sections of the formation are solution mined to remove soluble minerals from the sections. Solution mining minerals may be performed before, during, and/or after the in situ heat treatment process.
  • the average temperature of one or more sections being solution mined may be maintained below about 120° C.
  • one or more sections of the formation are heated to remove water from the sections and/or to remove methane and other volatile hydrocarbons from the sections.
  • the average temperature may be raised from ambient temperature to temperatures below about 220° C. during removal of water and volatile hydrocarbons.
  • one or more sections of the formation are heated to temperatures that allow for movement and/or visbreaking of hydrocarbons in the formation.
  • the average temperature of one or more sections of the formation are raised to mobilization temperatures of hydrocarbons in the sections (for example, to temperatures ranging from 100° C. to 250° C., from 120° C. to 240° C., or from 150° C. to 230° C.).
  • one or more sections are heated to temperatures that allow for pyrolysis reactions in the formation.
  • the average temperature of one or more sections of the formation may be raised to pyrolysis temperatures of hydrocarbons in the sections (for example, temperatures ranging from 230° C. to 900° C., from 240° C. to 400° C. or from 250° C. to 350° C.).
  • Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that raise the temperature of hydrocarbons in the formation to desired temperatures at desired heating rates.
  • the rate of temperature increase through mobilization temperature range and/or pyrolysis temperature range for desired products may affect the quality and quantity of the formation fluids produced from the hydrocarbon containing formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the production of high quality, high API gravity hydrocarbons from the formation. Slowly raising the temperature of the formation through the mobilization temperature range and/or pyrolysis temperature range may allow for the removal of a large amount of the hydrocarbons present in the formation as hydrocarbon product.
  • a portion of the formation is heated to a desired temperature instead of slowly heating the temperature through a temperature range.
  • the desired temperature is 300° C., 325° C., or 350° C. Other temperatures may be selected as the desired temperature.
  • Superposition of heat from heat sources allows the desired temperature to be relatively quickly and efficiently established in the formation.
  • Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at a desired temperature.
  • Mobilization and/or pyrolysis products may be produced from the formation through production wells.
  • the average temperature of one or more sections is raised to mobilization temperatures and hydrocarbons are produced from the production wells.
  • the average temperature of one or more of the sections may be raised to pyrolysis temperatures after production due to mobilization decreases below a selected value.
  • the average temperature of one or more sections may be raised to pyrolysis temperatures without significant production before reaching pyrolysis temperatures.
  • Formation fluids including pyrolysis products may be produced through the production wells.
  • the average temperature of one or more sections may be raised to temperatures sufficient to allow synthesis gas production after mobilization and/or pyrolysis.
  • hydrocarbons may be raised to temperatures sufficient to allow synthesis gas production without significant production before reaching the temperatures sufficient to allow synthesis gas production.
  • synthesis gas may be produced in a temperature range from about 400° C. to about 1200° C., about 500° C. to about 1100° C., or about 550° C. to about 1000° C.
  • a synthesis gas generating fluid for example, steam and/or water
  • Synthesis gas may be produced from production wells.
  • Solution mining removal of volatile hydrocarbons and water, mobilizing hydrocarbons, pyrolyzing hydrocarbons, generating synthesis gas, and/or other processes may be performed during the in situ heat treatment process.
  • some processes may be performed after the in situ heat treatment process.
  • Such processes may include, but are not limited to, recovering heat from treated sections, storing fluids (for example, water and/or hydrocarbons) in previously treated sections, and/or sequestering carbon dioxide in previously treated sections.
  • FIG. 1 depicts a schematic view of an embodiment of a portion of the in situ heat treatment system for treating the hydrocarbon containing formation.
  • the in situ heat treatment system may include barrier wells 200 .
  • Barrier wells are used to form a barrier around a treatment area. The barrier inhibits fluid flow into and/or out of the treatment area.
  • Barrier wells include, but are not limited to, dewatering wells, vacuum wells, capture wells, injection wells, grout wells, freeze wells, or combinations thereof.
  • barrier wells 200 are dewatering wells. Dewatering wells may remove liquid water and/or inhibit liquid water from entering a portion of the formation to be heated, or to the formation being heated.
  • the barrier wells 200 are shown extending only along one side of heat sources 202 , but the barrier wells typically encircle all heat sources 202 used, or to be used, to heat a treatment area of the formation.
  • Heat sources 202 are placed in at least a portion of the formation.
  • Heat sources 202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 202 may also include other types of heaters. Heat sources 202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 202 through supply lines 204 .
  • Supply lines 204 may be structurally different depending on the type of heat source or heat sources used to heat the formation.
  • Supply lines 204 for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated in the formation.
  • electricity for an in situ heat treatment process may be provided by a nuclear power plant or nuclear power plants. The use of nuclear power may allow for reduction or elimination of carbon dioxide emissions from the in situ heat treatment process.
  • the heat input into the formation may cause expansion of the formation and geomechanical motion.
  • the heat sources may be turned on before, at the same time, or during a dewatering process.
  • Computer simulations may model formation response to heating. The computer simulations may be used to develop a pattern and time sequence for activating heat sources in the formation so that geomechanical motion of the formation does not adversely affect the functionality of heat sources, production wells, and other equipment in the formation.
  • Heating the formation may cause an increase in permeability and/or porosity of the formation. Increases in permeability and/or porosity may result from a reduction of mass in the formation due to vaporization and removal of water, removal of hydrocarbons, and/or creation of fractures. Fluid may flow more easily in the heated portion of the formation because of the increased permeability and/or porosity of the formation. Fluid in the heated portion of the formation may move a considerable distance through the formation because of the increased permeability and/or porosity. The considerable distance may be over 1000 m depending on various factors, such as permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid. The ability of fluid to travel considerable distance in the formation allows production wells 206 to be spaced relatively far apart in the formation.
  • Production wells 206 are used to remove formation fluid from the formation.
  • production well 206 includes a heat source.
  • the heat source in the production well may heat one or more portions of the formation at or near the production well.
  • the amount of heat supplied to the formation from the production well per meter of the production well is less than the amount of heat applied to the formation from a heat source that heats the formation per meter of the heat source.
  • Heat applied to the formation from the production well may increase formation permeability adjacent to the production well by vaporizing and removing liquid phase fluid adjacent to the production well and/or by increasing the permeability of the formation adjacent to the production well by formation of macro and/or micro fractures.
  • More than one heat source may be positioned in the production well.
  • a heat source in a lower portion of the production well may be turned off when superposition of heat from adjacent heat sources heats the formation sufficiently to counteract benefits provided by heating the formation with the production well.
  • the heat source in an upper portion of the production well may remain on after the heat source in the lower portion of the production well is deactivated. The heat source in the upper portion of the well may inhibit condensation and reflux of formation fluid.
  • the heat source in production well 206 allows for vapor phase removal of formation fluids from the formation.
  • Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, (3) increase production rate from the production well as compared to a production well without a heat source, (4) inhibit condensation of high carbon number compounds (C 6 hydrocarbons and above) in the production well, and/or (5) increase formation permeability at or proximate the production well.
  • Subsurface pressure in the formation may correspond to the fluid pressure generated in the formation. As temperatures in the heated portion of the formation increase, the pressure in the heated portion may increase as a result of thermal expansion of in situ fluids, increased fluid generation and vaporization of water. Controlling rate of fluid removal from the formation may allow for control of pressure in the formation. Pressure in the formation may be determined at a number of different locations, such as near or at production wells, near or at heat sources, or at monitor wells.
  • Formation fluid may be produced from the formation when the formation fluid is of a selected quality.
  • the selected quality includes an API gravity of at least about 20°, 30°, or 40°.
  • Inhibiting production until at least some hydrocarbons are mobilized and/or pyrolyzed may increase conversion of heavy hydrocarbons to light hydrocarbons
  • Inhibiting initial production may minimize the production of heavy hydrocarbons from the formation. Production of substantial amounts of heavy hydrocarbons may require expensive equipment and/or reduce the life of production equipment.
  • hydrocarbons in the formation may be heated to mobilization and/or pyrolysis temperatures before substantial permeability has been generated in the heated portion of the formation.
  • An initial lack of permeability may inhibit the transport of generated fluids to production wells 206 .
  • fluid pressure in the formation may increase proximate heat sources 202 .
  • the increased fluid pressure may be released, monitored, altered, and/or controlled through one or more heat sources 202 .
  • selected heat sources 202 or separate pressure relief wells may include pressure relief valves that allow for removal of some fluid from the formation.
  • pressure generated by expansion of mobilized fluids, pyrolysis fluids or other fluids generated in the formation may be allowed to increase although an open path to production wells 206 or any other pressure sink may not yet exist in the formation.
  • the fluid pressure may be allowed to increase towards a lithostatic pressure.
  • Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure.
  • fractures may form from heat sources 202 to production wells 206 in the heated portion of the formation.
  • the generation of fractures in the heated portion may relieve some of the pressure in the portion.
  • Pressure in the formation may have to be maintained below a selected pressure to inhibit unwanted production, fracturing of the overburden or underburden, and/or coking of hydrocarbons in the formation.
  • pressure in the formation may be varied to alter and/or control a composition of formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid in the formation fluid, and/or to control an API gravity of formation fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component.
  • the condensable fluid component may contain a larger percentage of olefins.
  • pressure in the formation may be maintained high enough to promote production of formation fluid with an API gravity of greater than 20°. Maintaining increased pressure in the formation may inhibit formation subsidence during in situ heat treatment. Maintaining increased pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to treatment facilities.
  • Maintaining increased pressure in a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality and of relatively low molecular weight. Pressure may be maintained so that formation fluid produced has a minimal amount of compounds above a selected carbon number.
  • the selected carbon number may be at most 25, at most 20, at most 12, or at most 8.
  • Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor. Maintaining increased pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor.
  • High carbon number compounds and/or multi-ring hydrocarbon compounds may remain in a liquid phase in the formation for significant time periods. The significant time periods may provide sufficient time for the compounds to pyrolyze to form lower carbon number compounds.
  • Generation of relatively low molecular weight hydrocarbons is believed to be due, in part, to autogenous generation and reaction of hydrogen in a portion of the hydrocarbon containing formation.
  • maintaining an increased pressure may force hydrogen generated during pyrolysis into the liquid phase within the formation.
  • Heating the portion to a temperature in a pyrolysis temperature range may pyrolyze hydrocarbons in the formation to generate liquid phase pyrolyzation fluids.
  • the generated liquid phase pyrolyzation fluids components may include double bonds and/or radicals.
  • Hydrogen (H 2 ) in the liquid phase may reduce double bonds of the generated pyrolyzation fluids, thereby reducing a potential for polymerization or formation of long chain compounds from the generated pyrolyzation fluids.
  • H 2 may also neutralize radicals in the generated pyrolyzation fluids.
  • H 2 in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation.
  • Formation fluid produced from production wells 206 may be transported through collection piping 208 to treatment facilities 210 .
  • Formation fluids may also be produced from heat sources 202 .
  • fluid may be produced from heat sources 202 to control pressure in the formation adjacent to the heat sources.
  • Fluid produced from heat sources 202 may be transported through tubing or piping to collection piping 208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 210 .
  • Treatment facilities 210 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and/or other systems and units for processing produced formation fluids.
  • the treatment facilities may form transportation fuel from at least a portion of the hydrocarbons produced from the formation.
  • the transportation fuel may be jet fuel, such as JP-8.
  • Formation fluid may be hot when produced from the formation through the production wells.
  • Hot formation fluid may be produced during solution mining processes and/or during in situ heat treatment processes.
  • electricity may be generated using the heat of the fluid produced from the formation.
  • heat recovered from the formation after the in situ process may be used to generate electricity.
  • the generated electricity may be used to supply power to the in situ heat treatment process.
  • the electricity may be used to power heaters, or to power a refrigeration system for forming or maintaining a low temperature barrier.
  • Electricity may be generated using a Kalina cycle, Rankine cycle or other thermodynamic cycle.
  • the working fluid for the cycle used to generate electricity is aqua ammonia.
  • FIGS. 2 and 3 depict schematic representations of systems for producing crude products and/or commercial products from the in situ heat treatment process liquid stream and/or the in situ heat treatment process gas stream.
  • formation fluid 212 enters fluid separation unit 214 and is separated into in situ heat treatment process liquid stream 216 , in situ heat treatment process gas 218 and aqueous stream 220 .
  • liquid stream 216 may be transported to other processing units and/or facilities.
  • fluid separation unit 214 includes a quench zone.
  • quenching fluid such as water, nonpotable water, hydrocarbon diluent, and/or other components may be added to the formation fluid to quench and/or cool the formation fluid to a temperature suitable for handling in downstream processing equipment.
  • Quenching the formation fluid may inhibit formation of compounds that contribute to physical and/or chemical instability of the fluid (for example, inhibit formation of compounds that may precipitate from solution, contribute to corrosion, and/or fouling of downstream equipment and/or piping).
  • the quenching fluid may be introduced into the formation fluid as a spray and/or a liquid stream. In some embodiments, the formation fluid is introduced into the quenching fluid.
  • the formation fluid is cooled by passing the fluid through a heat exchanger to remove some heat from the formation fluid.
  • the quench fluid may be added to the cooled formation fluid when the temperature of the formation fluid is near or at the dew point of the quench fluid. Quenching the formation fluid near or at the dew point of the quench fluid may enhance solubilization of salts that may cause chemical and/or physical instability of the quenched fluid (for example, ammonium salts).
  • an amount of water used in the quench is minimal so that salts of inorganic compounds and/or other components do not separate from the mixture.
  • the quench fluid may be separated from the quench mixture and recycled to the quench zone with a minimal amount of treatment.
  • Heat produced from the quench may be captured and used in other facilities.
  • vapor may be produced during the quench. The produced vapor may be sent to gas separation unit 222 and/or sent to other facilities for processing.
  • Gas separation unit 222 may include a physical treatment system and/or a chemical treatment system.
  • the physical treatment system may include, but is not limited to, a membrane unit, a pressure swing adsorption unit, a liquid absorption unit, and/or a cryogenic unit.
  • the chemical treatment system may include units that use amines (for example, diethanolamine or di-isopropanolamine), zinc oxide, sulfolane, water, or mixtures thereof in the treatment process.
  • gas separation unit 222 uses a Sulfinol gas treatment process for removal of sulfur compounds.
  • Carbon dioxide may be removed using Catacarb® (Catacarb, Overland Park, Kans., U.S.A.) and/or Benfield (UOP, Des Plaines, Ill., U.S.A.) gas treatment processes.
  • the gas separation unit is a rectified adsorption and high pressure fractionation unit.
  • in situ heat treatment process gas is treated to remove at least 50%, at least 60%, at least 70%, at least 80% or at least 90% by volume of ammonia present in the gas stream.
  • in situ heat conversion treatment gas 218 removes sulfur compounds, carbon dioxide, and/or hydrogen to produce gas hydrocarbon stream 224 .
  • in situ heat treatment process gas 218 includes about 20 vol % hydrogen, about 30% methane, about 12% carbon dioxide, about 14 vol % C 2 hydrocarbons, about 5 vol % hydrogen sulfide, about 10 vol % C 3 hydrocarbons, about 7 vol % C 4 hydrocarbons, about 2 vol % C 5 hydrocarbons, and mixtures thereof, with the balance being heavier hydrocarbons, water, ammonia, COS, thiols and thiophenes.
  • Gas hydrocarbon stream 224 includes hydrocarbons having a carbon number of at least 3.
  • in situ treatment process gas 218 may be cryogenically treated as described in U.S. Published Patent Application No. 2009-0071652 to Vinegar et al. Cryogenic treatment of an in situ process gas may produce a gas stream acceptable for sale, transportation, and/or use as a fuel. It would be advantageous to separate in situ treatment process gas 218 at the treatment site to produce streams useable as energy sources to lower overall energy costs.
  • streams containing hydrocarbons and/or hydrogen may be used as fuel for burners and/or process equipment.
  • Streams containing sulfur compounds may be used as fuel for burners.
  • Streams containing one or more carbon oxides and/or hydrocarbons may be used to form barriers around a treatment site.
  • Streams containing hydrocarbons having a carbon number of at most 2 may be provided to ammonia processing facilities and/or barrier well systems.
  • In situ heat treatment process gas 218 may include a sufficient amount of hydrogen such that the freezing point of carbon dioxide is depressed. Depression of the freezing point of carbon dioxide may allow cryogenic separation of hydrogen and/or hydrocarbons from the carbon dioxide using distillation methods instead of removing the carbon dioxide by cryogenic precipitation methods. In some embodiments, the freezing point of carbon dioxide may be depressed by adjusting the concentration of molecular hydrogen and/or addition of heavy hydrocarbons to the process gas stream.
  • the process gas stream may include microscopic/molecular species of mercury and/or compounds of mercury.
  • the process gas stream may include dissolved, entrained or solid particulates of metallic mercury, ionic mercury, organometallic compounds of mercury (for example, alkyl mercury), or inorganic compounds of mercury (for example, mercury sulfide).
  • the process gas stream may be processed through a membrane filtration system used for filtering liquid hydrocarbon stream 232 described herein and/or as described in International Application No. WO 2008/116864 to Den Boestert et al., which is incorporated herein by reference, to remove mercury or mercury compounds from the process gas stream described below.
  • the filtered process gas stream may have a mercury content of 100 ppbw (parts per billion by weight) or less, 25 ppbw or less, 5 ppbw or less, 2 ppbw or less, or 1 ppbw or less.
  • the desalting unit may produce a liquid hydrocarbon stream and a salty process liquid stream.
  • In situ heat treatment process liquid stream 216 enters liquid separation unit 226 .
  • Separation unit 226 may include one or more distillation units.
  • separation of in situ heat treatment process liquid stream 216 produces gas hydrocarbon stream 228 , salty process liquid stream 230 , and liquid hydrocarbon stream 232 .
  • Gas hydrocarbon stream 228 may include hydrocarbons having a carbon number of at most 5. A portion of gas hydrocarbon stream 228 may be combined with gas hydrocarbon stream 224 .
  • Salty process liquid stream 230 may be processed as described in the discussion of FIG. 3 .
  • Salty process liquid stream 230 may include hydrocarbons having a boiling point above 260° C.
  • salty process liquid stream 230 enters desalting unit 234 .
  • salty process liquid stream 230 may be treated to form liquid stream 236 using known desalting and water removal methods.
  • Liquid stream 236 may enter separation unit 238 .
  • separation unit 238 liquid stream 236 is separated into bottoms stream 240 and hydrocarbon stream 242 .
  • hydrocarbon stream 242 may have a boiling range distribution between about 200° C. and about 350° C., between about 220° C. and 340° C., between about 230° C. and 330° C. or between about 240° C. and 320° C.
  • At least 50%, at least 70%, or at least 90% by weight of the total hydrocarbons in hydrocarbon stream 242 have a carbon number from 8 to 13.
  • About 50% to about 100%, about 60% to about 95%, about 70% to about 90%, or about 75% to 85% by weight of liquid stream may have a carbon number distribution from 8 to 13.
  • At least 50% by weight of the total hydrocarbons in the separated liquid stream may have a carbon number from about 9 to 12 or from 10 to 11.
  • hydrocarbon stream 242 has at most 15%, at most 10%, at most 5% by weight of naphthenes; at least 70%, at least 80%, or at least 90% by weight total paraffins; at most 5%, at most 3%, or at most 1% by weight olefins; and at most 30%, at most 20%, or at most 10% by weight aromatics.
  • hydrocarbon stream 242 has a nitrogen compound content of at least 0.01%, at least 0.1% or at least 0.4% by weight nitrogen compound.
  • the separated liquid stream may have a sulfur compound content of at least 0.01%, at least 0.5% or at least 1% by weight sulfur compound.
  • Hydrocarbon stream 242 enters hydrotreating unit 244 .
  • liquid stream 236 may be hydrotreated to form compounds suitable for processing to hydrogen and/or commercial products.
  • Liquid hydrocarbon stream 232 from liquid separation unit 226 may include hydrocarbons having a boiling range distribution from about 25° C. to up to about 538° C. or from about 25° C. to about 500° C. at atmospheric pressure.
  • liquid hydrocarbon stream 232 includes hydrocarbons having a boiling point up to 260° C.
  • Liquid hydrocarbon stream 232 may include entrained asphaltenes and/or other compounds that may contribute to the instability of hydrocarbon streams.
  • liquid hydrocarbon stream 232 is a naphtha/kerosene fraction that includes entrained, partially dissolved, and/or dissolved asphaltenes and/or high molecular weight compounds that may contribute to phase instability of the liquid hydrocarbon stream.
  • liquid hydrocarbon stream 232 may include at least 0.5% by weight asphaltenes, 1% by weight asphaltenes or at least 5% by weight asphaltenes. In some embodiments, liquid hydrocarbon stream 232 may include at most 5% by volume, at most 3% by volume, or at most 1% by volume of compounds having a boiling point of at least 335° C., at least 500° C. or at least 750° C. at atmospheric pressure.
  • liquid hydrocarbon stream 232 may include small amounts of dissolved, entrained or solid particulates of metals or metal compounds that may not be removed through conventional filtration methods.
  • Metals and/or metal compounds which may be present in the liquid hydrocarbon stream include iron, copper, mercury, calcium, sodium; silicon or compounds thereof.
  • a total amount of metals and/or metal compounds in the liquid hydrocarbon steam may range from 100 ppbw to about 1000 ppbw.
  • the asphaltenes and other components may become less soluble in the liquid hydrocarbon stream.
  • components in the produced fluids and/or components in the separated hydrocarbons may form two phases and/or become insoluble.
  • Formation of two phases, through flocculation of asphaltenes, change in concentration of components in the produced fluids, change in concentration of components in separated hydrocarbons, and/or precipitation of components may cause processing problems (for example, plugging) and/or result in hydrocarbons that do not meet pipeline, transportation, and/or refining specifications.
  • processing problems for example, plugging
  • further treatment of the produced fluids and/or separated hydrocarbons is necessary to produce products with desired properties.
  • the P-value of the separated hydrocarbons may be monitored and the stability of the produced fluids and/or separated hydrocarbons may be assessed. Typically, a P-value that is at most 1.0 indicates that flocculation of asphaltenes from the separated hydrocarbons may occur. If the P-value is initially at least 1.0 and such P-value increases or is relatively stable during heating, then this indicates that the separated hydrocarbons are relatively stable.
  • Liquid hydrocarbon stream 232 may be treated to at least partially remove asphaltenes and/or other compounds that may contribute to instability. Removal of the asphaltenes and/or other compounds that may contribute to instability may inhibit plugging in downstream processing units. Removal of the asphaltenes and/or other compounds that may contribute to instability may enhance processing unit efficiencies and/or prevent plugging of transportation pipelines.
  • Liquid hydrocarbon stream 232 may enter filtration system 246 .
  • Filtration system 246 separates at least a portion of the asphaltenes and/or other compounds that contribute to instability from liquid hydrocarbon stream 232 .
  • filtration system 246 is skid mounted. Skid mounting filtration system 246 may allow the filtration system to be moved from one processing unit to another.
  • filtration system 246 includes one or more membrane separators, for example, one or more nanofiltration membranes or one or more reverse osmosis membranes. Use of a filtration system that operates at below ambient, ambient, or slightly higher than ambient temperatures may reduce energy costs as compared to conventional catalytic and/or thermal methods to remove asphaltenes from a hydrocarbon stream.
  • the membranes may be ceramic membranes and/or polymeric membranes.
  • the ceramic membranes may be ceramic membranes having a molecular weight cut off of at most 2000 Daltons (Da), at most 1000 Da, or at most 500 Da. Ceramic membranes may not swell during removal of the desired materials from a substrate (for example, asphaltenes from the liquid stream). In addition, ceramic membranes may be used at elevated temperatures. Examples of ceramic membranes include, but are not limited to, nanoporous and/or mesoporous titania, mesoporous gamma-alumina, mesoporous zirconia, mesoporous silica, and combinations thereof.
  • Polymeric membranes may include top layers made of dense membrane and base layers (supports) made of porous membranes.
  • the polymeric membranes may be arranged to allow the liquid stream (permeate) to flow first through the top layers and then through the base layer so that the pressure difference over the membrane pushes the top layer onto the base layer.
  • the polymeric membranes are organophilic or hydrophobic membranes so that water present in the liquid stream is retained or substantially retained in the retentate.
  • the dense membrane layer of the polymeric membrane may separate at least a portion or substantially all of the asphaltenes from liquid hydrocarbon stream 232 .
  • the dense polymeric membrane has properties such that liquid hydrocarbon stream 232 passes through the membrane by dissolving in and diffusing through the structure of dense membrane. At least a portion of the asphaltenes may not dissolve and/or diffuse through the dense membrane, thus they are removed. The asphaltenes may not dissolve and/or diffuse through the dense membrane because of the complex structure of the asphaltenes and/or their high molecular weight.
  • the dense membrane layer may include cross-linked structure as described in WO 96/27430 to Schmidt et al., which is incorporated by reference herein. A thickness of the dense membrane layer may range from 1 micrometer to 15 micrometers, from 2 micrometers to 10 micrometers, or from 3 micrometers to 5 micrometers.
  • the dense membrane may be made from polysiloxane, poly-di-methyl siloxane, poly-octyl-methyl siloxane, polyimide, polyaramide, poly-tri-methyl silyl propyne, or mixtures thereof.
  • Porous base layers may be made of materials that provide mechanical strength to the membrane.
  • the porous base layers may be any porous membranes used for ultra filtration, nanofiltration, and/or reverse osmosis. Examples of such materials are polyacrylonitrile, polyamideimide in combination with titanium oxide, polyetherimide, polyvinylidenedifluoroide, polytetrafluoroethylene, or combinations thereof.
  • the pressure difference across the membrane may range from about 0.5 MPa to about 6 MPa, from about 1 MPa to about 5 MPa, or from about 2 MPa to about 4 MPa.
  • a temperature of the unit during separation may range from the pour point of liquid hydrocarbon stream 232 up to 100° C., from about ⁇ 20° C. to about 100° C., from about 10° C. to about 90° C., or from about 20° C. to about 85° C.
  • the permeate flux rate may be at most 50% of the initial flux, at most 70% of the initial flux, or at most 90% of the initial flux.
  • a weight recovery of the permeate on feed may range from about 50% by weight to 97% by weight, from about 60% by weight to 90% by weight, or from about 70% by weight to 80% by weight.
  • Filtration system 246 may include one or more membrane separators.
  • the membrane separators may include one or more membrane modules. When two or more membrane separators are used, the separators may be arranged in a parallel-operated (groups of) membrane separators that include a single separation step. In some embodiments, two or more sequential separation steps are performed, where the retentate of the first separation step is used as the feed for a second separation step.
  • membrane modules include, but are not limited to, spirally wound modules, plate and frame modules, hollow fibers, and tubular modules. Membrane modules are described in Encyclopedia of Chemical Engineering, 4 th Ed., 1995, John Wiley & Sons Inc., Vol. 16, pages 158-164.
  • spirally wound modules are described in, for example, WO/2006/040307 to Den Boestert et al., U.S. Pat. No. 5,102,551 to Pasternak; U.S. Pat. No. 5,093,002 to Pasternak; U.S. Pat. No. 5,133,851 to Bitter et al.; U.S. Pat. No. 5,275,726 to Feimer et al.; U.S. Pat. No. 5,458,774 to Mannapperuma; and U.S. Pat. No. 7,351,873 to Cederl ⁇ f et al., all of which are incorporated by reference herein.
  • a spirally wound module is used when a dense membrane is used in filtration system 246 .
  • a spirally wound module may include a membrane assembly of two membrane sheets between which a permeate spacer sheet is sandwiched. The membrane assembly may be sealed at three sides. The fourth side is connected to a permeate outlet conduit such that the area between the membranes is in fluid communication with the interior of the conduit.
  • a feed spacer sheet may be arranged on top of one of the membranes. The assembly with feed spacer sheet is rolled up around the permeate outlet conduit to form a substantially cylindrical spirally wound membrane module.
  • the feed spacer may have a thickness of at least 0.6 mm, at least 1 mm, or at least 3 mm to allow sufficient membrane surface to be packed into the spirally wound module.
  • the feed spacer is a woven feed spacer.
  • the feed mixture may be passed from one end of the cylindrical module between the membrane assemblies along the feed spacer sheet sandwiched between feed sides of the membranes. Part of the feed mixture passes through either one of the membrane sheets to the permeate side. The resulting permeate flows along the permeate spacer sheet into the permeate outlet conduit.
  • the membrane separation is a continuous process.
  • Liquid stream 232 passes over the membrane due to the pressure difference to obtain filtered liquid stream 248 (permeate) and/or recycle liquid stream 250 (retentate).
  • filtered liquid stream 248 may have reduced concentrations of asphaltenes and/or high molecular weight compounds that may contribute to phase instability.
  • Continuous recycling of recycle liquid stream 250 through the filter system can increase the production of filtered liquid stream 248 to as much as 95% of the original volume of filtered liquid stream 248 .
  • Recycle liquid stream 250 may be continuously recycled through a spirally wound membrane module for at least 10 hours, for at least one day, or for at least one week without cleaning the feed side of the membrane.
  • the flow rate of 250 is used to set a certain required fluid velocity through the membrane modules).
  • the permeate may have a final boiling point of at most 470° C., at most 450° C., or at most at most 420° C.
  • the permeate may have a final boiling point range from at least 25° C. to about 470° C., from about 50° C. to about 450° C., or at least 75° C. to about 420° C.
  • the permeate may have from about 0.001% to about 5%, from about 0.01% to about 3%, or from about 0.1% to about 1%, by volume of compounds having a boiling point of at least 335° C.
  • the permeate may have undetectable amounts of asphaltenes or substantially undetectable amounts of asphaltenes.
  • the permeate may have a total metal content that is less than about 60% on a weight basis than the metal content of the liquid hydrocarbon stream.
  • the permeate may have a total metal content from about 1 ppbw to about 600 ppbw, from about 10 ppbw to about 300 ppbw, or from about 100 to about 150 ppbw.
  • asphaltene enriched stream 252 may include a high concentration of asphaltenes and/or high molecular weight compounds.
  • the retentate has at least 50% by volume of compounds having a boiling point of at least 700° C.
  • the retentate has at least 50%, at least 70%, at least 80%, or at least 90% by volume of compounds having a boiling point of at least 325° C.
  • the retentate has at least 50% by volume of compounds having a boiling point of at least 350° C., at least 400° C., or at least 700° C.
  • the permeate has at most 2% by volume of compounds having a boiling point of at least 335° C. and the retentate has at least 25% by volume of compounds having a boiling point of at least 750° C.
  • Asphaltene enriched stream 252 may be provided to separation unit 238 or to other units for further processing.
  • At least a portion of filtered liquid stream 248 may be sent to hydrotreating unit 244 for further processing. In some embodiments, at least a portion of filtered liquid stream 248 may be sent to other processing units.
  • filtered liquid stream 248 enters separation unit 254 .
  • filtered liquid stream 248 may be separated into hydrocarbon stream 256 and liquid hydrocarbon stream 258 .
  • Hydrocarbon stream 268 may be rich in aromatic hydrocarbons.
  • Liquid hydrocarbon stream 258 may include a small amount of aromatic hydrocarbons.
  • Liquid hydrocarbon stream 258 may include hydrocarbons having a boiling point up to 260° C.
  • Liquid hydrocarbon stream 258 may enter hydrotreating unit 244 and/or other processing units.
  • Hydrocarbon stream 256 may include aromatic hydrocarbons and hydrocarbons having a boiling point up to about 260° C.
  • a content of aromatics in aromatic rich stream 256 may be at most 90%, at most 70%, at most 50%, or most 10% of the aromatic content of filtered liquid stream 248 , as measured by UV analysis such as method SMS-2714.
  • Aromatic rich stream 256 may suitable for use as a diluent for undesirable streams that may not otherwise be suitable for additional processing.
  • the undesirable streams may have low P-values, phase instability, and/or asphaltenes. Addition of aromatic rich stream 256 to the undesirable streams may allow the undesirable streams to be processed and/or transported, thus increasing the economic value of the stream undesirable streams.
  • Aromatic rich stream 256 may be sold as a diluent and/or used as a diluent for produced fluids. All or a portion of aromatic rich stream 254 may be recycled to separation unit 226 .
  • membrane separation unit 254 includes one or more membrane separators, for example, one or more nanofiltration membranes and/or one or more reverse osmosis membranes.
  • the membrane may be a ceramic membrane and/or a polymeric membrane.
  • the ceramic membrane may be a ceramic membrane having a molecular weight cut off of at most 2000 Daltons (Da), at most 1000 Da, or at most 500 Da.
  • the polymeric membrane includes a top layer made of a dense membrane and a base layer (support) made of a porous membrane.
  • the polymeric membrane may be arranged to allow the liquid stream (permeate) to flow first through the dense membrane top layer and then through the base layer so that the pressure difference over the membrane pushes the top layer onto the base layer.
  • the dense polymeric membrane has properties such that as liquid hydrocarbon stream 248 passes through the membrane aromatic hydrocarbons are selectively separated from the liquid hydrocarbon stream to form aromatic rich stream 256 .
  • the dense membrane layer may separate at least a portion of or substantially all of the aromatics from liquid hydrocarbon stream 248 .
  • the dense membrane may be a silicon based membrane, a polyamide based membrane and/or a polyol membrane.
  • Aromatic selective membranes may be purchased from W. R. Grace & Co. (New York, USA), MTR-Inc, California, USA PolyAn (Berlin, Germany), GMT, Rheinfelden, Germany and/or Borsig Membrane Technology (Berlin, Germany).
  • Liquid stream 260 (retentate) from membrane separation unit 254 may be recycled back to the membrane separation unit. Continuous recycling of recycle liquid stream 260 idem through nanofiltration system can increase the production of aromatic rich stream 256 to as much as 95% of the original volume of the filtered liquid stream. Recycle liquid stream 260 may be continuously recycled through a spirally wound membrane module for at least 10 hours, for at least one day, for at least one week or until the desired content of aromatics in aromatic rich stream 256 is obtained. Upon completion of the filtration, or when the retentate includes an acceptable amount of aromatics, liquid stream 260 (retentate) from separation unit 254 may be sent to hydrotreating unit 244 and/or other processing units.
  • Membranes of separation unit 254 may be ceramic membranes and/or polymeric membranes.
  • the pressure difference across the membrane may range from about 0.5 MPa to about 6 MPa, from about 1 MPa to about 5 MPa, or from about 2 MPa to about 4 MPa.
  • Temperature of separation unit 254 during separation may range from the pour point of the liquid hydrocarbon stream 248 up to 100° C., from about ⁇ 20° C. to about 100° C., from about 10° C. to about 90° C., or from about 20° C. to about 85° C.
  • the permeate flux rate may be at most 50% of the initial flux, at most 70% of the initial flux, or at most 90% of the initial flux.
  • a weight recovery of the permeate on feed may range from about 50% by weight to 97% by weight, from about 60% by weight to 90% by weight, or from about 70% by weight to 80% by weight.
  • liquid hydrocarbon streams produced from a formation may include organonitrogen compounds.
  • Organonitrogen compounds are known to poison precious metal catalyst used for treating hydrocarbon streams to make products suitable for commercial sale and/or transportation (for example, transportation fuels and/or lubricating oils).
  • the formation fluids may include nitrogen levels such that process facilities may deem the fluid unsuitable for processing.
  • Organonitrogen compounds may be removed through catalytic hydrogenation methods and/or solvent extraction methods.
  • Catalytic hydrogenation methods require high temperatures and catalyst that are not subject to poisoning by nitrogen compounds.
  • the catalytic hydrogenation methods may require high temperatures and/or pressures in addition to requiring high amounts of hydrogen.
  • Hydrogen may not be readily available and/or may need to be manufactured. Since hydrogen has to be supplied for denitrogenation, the use of high amounts of hydrogen may increase the overall cost for removal of nitrogen from the fluids such that process facilities deem the fluids unsuitable.
  • Liquid hydrocarbon streams may be extracted with aqueous acid streams to produce a hydrocarbon stream having a minimal amount of organonitrogen compounds and an aqueous stream.
  • the aqueous stream may contain organonitrogen salts. Further processing of the aqueous stream (e.g., distillation and/or treatment with base) may result production of a stream rich in organonitrogen compounds.
  • the stream rich in organonitrogen stream may be used as diluent for heavy oil and/or sent to other processing units.
  • 4,287,051 to Curtin describes a method of denitrogenating viscous oils containing a relatively high content of nitrogenous compounds by extracting nitrogenous compounds from a first portion of a viscous oil with an operable acid solvent to produce a raffinate oil having a relatively low concentration of nitrogenous compounds and a extract stream having a high concentration of nitrogenous compounds.
  • the acid solvent is recovered from the extract stream, simultaneously producing a small volume stream of low viscosity oil containing a high concentration of the nitrogenous compounds and referred to as a high nitrogen content oil.
  • the low viscosity high nitrogen content oil is admixed with the remaining first high viscosity bottoms to provide a pumpable mixed stream.
  • aqueous extraction and/or hydrogenation of hydrocarbon streams may produce liquid hydrocarbon streams having a low organonitrogen content, more efficient processes and less costly processes to treat the high nitrogen content oil are desirable. In addition, processes that allow for recycle of waste or low value streams are desirable.
  • liquid stream 236 includes organonitrogen compounds. In some embodiments, liquid stream 236 includes from about 0.1% to greater than 2% by weight nitrogen compounds. In some embodiments, liquid stream 236 includes from about 0.2% to about 1.5% or from 0.5% to about 1% by weight nitrogen compounds.
  • Organonitrogen compounds for example, alkyl amines, aromatic amines, alkyl amides, aromatic amides, pyridines, pyrazoles, and oxazoles may poison precious metal catalyst used for treating hydrocarbon streams to make products suitable for commercial sale and/or transportation (for example, transportation fuels and/or lubricating oils). Removal of organonitrogen compounds from the liquid hydrocarbon stream prior to catalytic treatment of the liquid hydrocarbon stream may enhance catalyst life of downstream processes. Removal of organonitrogen compounds may allow less severe conditions be used in downstream applications.
  • liquid stream 236 enters separation unit 262 .
  • liquid stream 236 is passed through one or more filtration units in separation unit 262 to remove solids from the liquid stream.
  • liquid stream 236 may be treated with aqueous acid solution 264 to form an aqueous stream 266 and non-aqueous stream 268 .
  • a volume ratio of liquid stream to aqueous acid solution ranges from 0.2 to 0.3 or is about 0.25.
  • Treatment of liquid stream 236 with aqueous acid solution 264 may be conducted at a temperature ranging from about 90° C. to about 150° C. at a pressures ranging from about 0.3 MPa to about 0.4 MPa.
  • Non-aqueous stream 268 may include non-organonitrogen hydrocarbons.
  • non-organonitrogen hydrocarbons include compounds that contain only hydrogen and carbon.
  • non-aqueous stream 268 contains at most 0.01% by weight organonitrogen compounds.
  • non-aqueous stream 268 contains from about 200 ppmw to about 1000 ppmw, from about 300 ppmw to about 800 ppmw, or from about 500 ppmw to about 700 ppm organonitrogen compounds.
  • Non-aqueous stream 268 may enter hydrotreating unit 244 for further processing to make products suitable for transportation and/or sale. In some embodiments, further processing of non-aqueous stream 268 is not necessary.
  • Aqueous acid solution 264 includes water and acids suitable to complex with nitrogen compounds (for example, sulfuric acid, phosphoric acid, acetic acid, formic acid, other suitable acidic compounds or mixtures thereof).
  • Aqueous stream 266 includes salts of the organonitrogen compounds and acid and water. At least a portion of aqueous stream 266 is sent to separation unit 270 .
  • separation unit 270 aqueous stream 266 is separated (for example, distilled) to form aqueous acid stream 264 ′ and concentrated organonitrogen stream 272 .
  • Concentrated organonitrogen stream 272 includes organonitrogen compounds, water, and/or acid.
  • Separated aqueous stream 264 ′ may be introduced into separation unit 262 . In some embodiments, separated aqueous stream 264 ′ is combined with aqueous acid solution 264 prior to entering the separation unit.
  • At least a portion of aqueous stream 266 and/or concentrated organonitrogen stream 272 are introduced in a hydrocarbon portion or layer of subsurface formation that has been at least partially treated by an in situ heat treatment process. Aqueous stream 266 and/or concentrated organonitrogen stream 272 may be heated prior to injection in the formation. In some embodiments, the hydrocarbon portion or layer In some embodiments, at least a portion of aqueous stream 266 and/or concentrated organonitrogen stream 272 are introduced in a hydrocarbon portion or layer of subsurface formation that has been at least partially treated by an in situ heat treatment process. Aqueous stream 266 and/or concentrated organonitrogen stream 272 may be heated prior to injection in the formation.
  • the hydrocarbon portion or layer includes a shale and/or nahcolite (for example, a nahcolite zone in the Piceance Basin).
  • the aqueous stream 266 and/or concentrated organonitrogen stream 272 is used a part of the water source for solution mining nahcolite from the formation.
  • the aqueous stream 266 and/or concentrated organonitrogen stream 272 is introduced in a portion of a formation that contains nahcolite after at least a portion of the nahcolite has been removed.
  • the aqueous stream 266 and/or concentrated organonitrogen stream 272 is introduced in a portion of a formation that contains nahcolite after at least a portion of the nahcolite has been removed and/or the portion has been at least partially treated using an in situ heat treatment process.
  • the hydrocarbon layer may be heated to temperatures above 200° C. prior to introduction of the aqueous stream.
  • Addition of streams that include organonitrogen compounds may increase the permeability of the hydrocarbon layer (for example, increase the permeability of the oil shale layer), thus flow of formation fluids from the heated hydrocarbon layer to other sections of the formation may be improved.
  • the organonitrogen compounds may form non-nitrogen containing hydrocarbons, amines, and/or ammonia and at least some of such non-nitrogen containing hydrocarbons, amines and/or ammonia may be produced.
  • at least some of the acid used in the extraction process is produced.
  • streams 242 , 248 , 258 , 268 from processes described in FIGS. 2 and 3 enter hydrotreating unit 244 and are contacted with hydrogen in the presence of one or more catalysts to produce hydrotreated liquid streams 274 , 276 .
  • non-aqueous stream 268 is hydrotreated in hydrotreating unit 244 to produce hydrotreated liquid stream 274 .
  • Hydrotreated liquid stream 274 has a nitrogen compound content of at most 200 ppm by weight, at most 150 ppm, at most 110 ppm, at most 50 ppm, or at most 10 ppm of nitrogen compounds.
  • the hydrotreated liquid stream may have a sulfur compound content of at most 1000 ppm, at most 500 ppm, at most 300 ppm, at most 100 ppm, or at most 10 ppm by weight of sulfur compounds.
  • Asphalt/bitumen compositions are a commonly used material for construction purposes, such as road pavement and/or roofing material. Residues from fractional and/or vacuum distillation may be used to prepare asphalt/bitumen compositions. Alternatively, asphalt/bitumen used in asphalt/bitumen compositions may be obtained from natural resources or by treating a crude oil in a de-asphalting unit to separate the asphalt/bitumen from lighter hydrocarbons in the crude oil. Asphalt/bitumen alone, however, often does not possess all the physical characteristics desirable for many construction purposes. Asphalt/bitumen may be susceptible to moisture loss, permanent deformation (for example, ruts and/or potholes), and/or cracking.
  • Modifiers may be added to asphalt/bitumen to form asphalt/bitumen compositions to improve weatherability of the asphalt/bitumen compositions.
  • modifiers include binders, adhesion improvers, antioxidants, extenders, fibers, fillers, oxidants, or combinations thereof.
  • adhesion improvers include fatty acids, inorganic acids, organic amines, amides, phenols, and polyamidoamines. These compositions may have improved characteristics as compared to asphalt/bitumen alone.
  • U.S. Pat. No. 4,325,738 to Plancher et al. describes addition of fractions removed from shale oil that contain high amounts of nitrogen may be used as moisture damage inhibiting agents in asphalt/bitumen compositions.
  • the high nitrogen fractions may be obtained by distillation and/or acid extraction. While the composition of the prior art is often effective in improving the weatherability of asphalt-aggregate compositions, asphalt/bitumen compositions having improved resistance to moisture loss, cracking, and deformation are still needed.
  • a residue stream generated from an in situ heat treatment (ISHT) process and/or through further treatment of the liquid stream generated from an ISHT process is blended with asphalt/bitumen to form an ISHT residue/asphalt/bitumen composition.
  • the ISHT residue/asphalt/bitumen blend may have enhanced water sensitivity and/or tensile strength.
  • the ISHT residue/asphalt/bitumen blend may absorb less water and/or have improved tensile strength modulus as compared to other asphalt/bitumen blends made with adhesion improvers.
  • ISHT residue/asphalt/bitumen blends may decrease cracking and/or pothole formation in paved roads as compared to asphalt/bitumen blends made with conventional adhesion improvers.
  • Use of ISHT residue in asphalt/bitumen compositions may allow the compositions to be made without or with reduced amounts of expensive adhesion improvers.
  • ISHT residue may be generated as bottoms stream 240 from separator 238 , and/or bottoms stream 278 from hydrotreating unit 244 .
  • ISHT residue may have at least 50% by weight or at least 80% by weight or at least 90% by weight of hydrocarbons having a boiling point above 538° C.
  • ISHT residue has an initial boiling point of at least 400° C. as determined by SIMDIS 750 , about 50% by weight asphaltenes, about 3% by weight saturates, about 10% by weight aromatics, and about 36% by weight resins as determined by SARA analysis.
  • ISHT residue may have a total metal content of about 1 ppm to about 500 ppm, from about 10 ppm to about 400 ppm, or from about 100 ppm to about 300 ppm of metals from Columns 1-14 of the Periodic Table.
  • ISHT residue may include about 2 ppm aluminum, about 5 ppm calcium, about 100 ppm iron, about 50 ppm nickel, about 10 ppm potassium, about 10 ppm of sodium, and about 5 ppm vanadium as determined by ICP test method such as ASTM Test Method D5185.
  • ISHT residue may be a hard material.
  • ISHT residue may exhibit a penetration of at most 3 at 60° C. (0.1 mm) as measured by ASTM Test Method D243, and a ring-and-ball (R&B) temperature of about 139° C. as determined by ASTM Test Method D36.
  • a blend of ISHT residue and asphalt/bitumen may be prepared by reducing the particle size of the ISHT residue (for example, crushing or pulverizing the ISHT residue) and heating the crushed ISHT residue to soften the ISHT particles.
  • the ISHT residue may melt at temperatures above 200° C.
  • Hot ISHT residue may be added to asphalt/bitumen at a temperature ranging from about 150° C. to about 200° C., from about 180° C. to about 195° C., or from about 185° C. to about 195° C. for a period of time to form an ISHT residue/asphalt/bitumen blend.
  • the ISHT residue/asphalt/bitumen composition may include from about 0.001% by weight to about 50% by weight, from about 0.05% by weight to about 25% by weight, or from about 0.1% by weight to about 5% by weight of ISHT residue.
  • the ISHT residue/asphalt/bitumen composition may include from about 99.999% by weight to about 50% by weight, from about 99.05% by weight to about 75% by weight, and from about 99.9% by weight to about 95% by weight of asphalt/bitumen.
  • the blend may include about 20% by weight ISHT residue and about 80% by weight asphalt/bitumen or about 8% by weight ISHT residue and 92% by weight asphalt/bitumen.
  • additives may be added to the ISHT residue/asphalt/bitumen composition. Additives include, but are not limited to, antioxidants, extenders, fibers, fillers, oxidants, or mixtures thereof.
  • the ISHT residue/asphalt/bitumen composition may be used as a binder in paving and/or roofing applications, for example, road paving, shingles, roofing felts, paints, pipecoating, briquettes, thermal and/or phonic insulation, and clay pigeons.
  • a sufficient amount of ISHT residue may be mixed with asphalt/bitumen to produce an ISHT residue/asphalt/bitumen composition having a 70/100 penetration grade as measured according to EN1426.
  • a mixture of about 8% by weight of ISHT residue and about 91% asphalt/bitumen has a penetration between 70 and 100.
  • the ISHT residue/asphalt/bitumen blend of 70/100 penetration grade is suitable for paving applications.
  • vertical or substantially vertical wells are formed in the formation.
  • horizontal or U-shaped wells are formed in the formation.
  • combinations of horizontal and vertical wells are formed in the formation.
  • a manufacturing approach for forming wellbores in the formation may be used due to the large number of wells that need to be formed for the in situ heat treatment process.
  • the manufacturing approach may be particularly applicable for forming wells for in situ heat treatment processes that utilize u-shaped wells or other types of wells that have long non-vertically oriented sections. Surface openings for the wells may be positioned in lines running along one or two sides of the treatment area.
  • FIG. 4 depicts a schematic representation of an embodiment of a system for forming wellbores of the in situ heat treatment process.
  • the manufacturing approach for forming wellbores may include: 1) delivering flat rolled steel to near site tube manufacturing plant that forms coiled tubulars and/or pipe for surface pipelines; 2) manufacturing large diameter coiled tubing that is tailored to the required well length using electrical resistance welding (ERW), wherein the coiled tubing has customized ends for the bottom hole assembly (BHA) and hang off at the wellhead; 3) deliver the coiled tubing to a drilling rig on a large diameter reel; 4) drill to total depth with coil and a retrievable bottom hole assembly; 5) at total depth, disengage the coil and hang the coil on the wellhead; 6) retrieve the BHA; 7) launch an expansion cone to expand the coil against the formation; 8) return empty spool to the tube manufacturing plant to accept a new length of coiled tubing; 9) move the gantry type drilling platform to the next well location; and 10) repeat.
  • ERP electrical resistance welding
  • In situ heat treatment process locations may be distant from established cities and transportation networks. Transporting formed pipe or coiled tubing for wellbores to the in situ process location may be untenable due to the lengths and quantity of tubulars needed for the in situ heat treatment process.
  • One or more tube manufacturing facilities 280 may be formed at or near to the in situ heat treatment process location.
  • the tubular manufacturing facility may form plate steel into coiled tubing.
  • the plate steel may be delivered to tube manufacturing facilities 280 by truck, train, ship or other transportation system.
  • different sections of the coiled tubing may be formed of different alloys.
  • the tubular manufacturing facility may use ERW to longitudinally weld the coiled tubing.
  • Tube manufacturing facilities 280 may be able to produce tubing having various diameters. Tube manufacturing facilities may initially be used to produce coiled tubing for forming wellbores. The tube manufacturing facilities may also be used to produce heater components, piping for transporting formation fluid to surface facilities, and other piping and tubing needs for the in situ heat treatment process.
  • Tube manufacturing facilities 280 may produce coiled tubing used to form wellbores in the formation.
  • the coiled tubing may have a large diameter.
  • the diameter of the coiled tubing may be from about 4 inches to about 8 inches in diameter. In some embodiments, the diameter of the coiled tubing is about 6 inches in diameter.
  • the coiled tubing may be placed on large diameter reels. Large diameter reels may be needed due to the large diameter of the tubing.
  • the diameter of the reel may be from about 10 m to about 50 m. One reel may hold all of the tubing needed for completing a single well to total depth.
  • tube manufacturing facilities 280 has the ability to apply expandable zonal inflow profiler (EZIP) material to one or more sections of the tubing that the facility produces.
  • EZIP expandable zonal inflow profiler
  • the EZIP material may be placed on portions of the tubing that are to be positioned near and next to aquifers or high permeability layers in the formation. When activated, the EZIP material forms a seal against the formation that may serve to inhibit migration of formation fluid between different layers.
  • the use of EZIP layers may inhibit saline formation fluid from mixing with non-saline formation fluid.
  • the size of the reels used to hold the coiled tubing may prohibit transport of the reel using standard moving equipment and roads. Because tube manufacturing facility 280 is at or near the in situ heat treatment location, the equipment used to move the coiled tubing to the well sites does not have to meet existing road transportation regulations and can be designed to move large reels of tubing. In some embodiments the equipment used to move the reels of tubing is similar to cargo gantries used to move shipping containers at ports and other facilities. In some embodiments, the gantries are wheeled units. In some embodiments, the coiled tubing may be moved using a rail system or other transportation system.
  • the coiled tubing may be moved from the tubing manufacturing facility to the well site using gantries 282 .
  • Drilling gantry 284 may be used at the well site. Several drilling gantries 284 may be used to form wellbores at different locations. Supply systems for drilling fluid or other needs may be coupled to drilling gantries 284 from central facilities 286 .
  • Drilling gantry 284 or other equipment may be used to set the conductor for the well. Drilling gantry 284 takes coiled tubing, passes the coiled tubing through a straightener, and a BHA attached to the tubing is used to drill the wellbore to depth.
  • a composite coil is positioned in the coiled tubing at tube manufacturing facility 280 .
  • the composite coil allows the wellbore to be formed without having drilling fluid flowing between the formation and the tubing.
  • the composite coil also allows the BHA to be retrieved from the wellbore.
  • the composite coil may be pulled from the tubing after wellbore formation.
  • the composite coil may be returned to the tubing manufacturing facility to be placed in another length of coiled tubing.
  • the BHAs are not retrieved from the wellbores.
  • drilling gantry 284 takes the reel of coiled tubing from gantry 282 .
  • gantry 282 is coupled to drilling gantry 284 during the formation of the wellbore.
  • the coiled tubing may be fed from gantry 282 to drilling gantry 284 , or the drilling gantry lifts the gantry to a feed position and the tubing is fed from the gantry to the drilling gantry.
  • the wellbore may be formed using the bottom hole assembly, coiled tubing and the drilling gantry.
  • the BHA may be self-seeking to the destination.
  • the BHA may form the opening at a fast rate. In some embodiments, the BHA forms the opening at a rate of about 100 meters per hour.
  • the tubing may be suspended from the wellhead.
  • An expansion cone may be used to expand the tubular against the formation.
  • the drilling gantry is used to install a heater and/or other equipment in the wellbore.
  • the drilling gantry may release gantry 282 with the empty reel or return the empty reel to the gantry.
  • Gantry 282 may take the empty reel back to tube manufacturing facility 280 to be loaded with another coiled tube.
  • Gantries 282 may move on looped path 290 from tube manufacturing facility 280 to well sites 288 and back to the tube manufacturing facility.
  • Drilling gantry 284 may be moved to the next well site. Global positioning satellite information, lasers and/or other information may be used to position the drilling gantry at desired locations. Additional wellbores may be formed until all of the wellbores for the in situ heat treatment process are formed.
  • positioning and/or tracking system may be utilized to track gantries 282 , drilling gantries 284 , coiled tubing reels and other equipment and materials used to develop the in situ heat treatment location.
  • Tracking systems may include bar code tracking systems to ensure equipment and materials arrive where and when needed.
  • Directionally drilled wellbores may be formed using steerable motors. Deviations in wellbore trajectory may be made using slide drilling systems or using rotary steerable systems.
  • the mud motor rotates the bit downhole with little or no rotation of the drilling string from the surface during trajectory changes.
  • the bottom hole assembly is fitted with a bent sub and/or a bent housing mud motor for directional drilling.
  • the bent sub and the drill bit are oriented in the desired direction.
  • the drill bit is rotated with the mud motor to set the trajectory.
  • Drill bit direction changes may be made by utilizing torque/rotary adjusting to control the drill bit in the desired direction.
  • the wellbore trajectory may be controlled. Torque and drag during sliding and rotating modes may limit the capabilities of slide mode drilling. Steerable motors may produce tortuosity in the slide mode. Tortuosity may make further sliding more difficult. Many methods have been developed, or are being developed, to improve slide drilling systems. Examples of improvements to slide drilling systems include agitators, low weight bits, slippery muds, and torque/toolface control systems.
  • Rotary steerable systems allow directional drilling with continuous rotation from the surface, thus making the need to slide the drill string unnecessary. Continuous rotation transfers weight to the drill bit more efficiently, thus increasing the rate of penetration and distance that can be drilled.
  • Current rotary steerable systems may be mechanically and/or electrically complicated with a consequently high cost of delivery.
  • the functionality is to “rock” the drilling string forward and backward with rotation to place a portion of the drilling string in rotation and leaving the lower end of the drilling string sliding.
  • This process has drawbacks such as the periodic reversals mean periodic “not rotating” episodes and consequent inefficiency in transfer of force for weight on the drill bit.
  • the rocking also requires “overhead” between drilling string connection torque capacity and operating torque to ensure the drilling string does not become unscrewed.
  • a dual motor rotating steerable system as described herein may reduce or eliminate many of the drawbacks of conventional rotating steerable systems.
  • a dual motor rotary steerable drilling system is used.
  • the dual motor rotary steerable system allows a bent sub and/or bent housing mud motor to change the trajectory of the drilling while the drilling string remains in rotary mode.
  • the dual motor rotary steerable system uses a second motor in the bottom hole assembly to rotate a portion of the bottom hole assembly in a direction opposite to the direction of rotation of the drilling string.
  • the addition of the second motor may allow continuous forward rotation of a drilling string while simultaneously controlling the drill bit and, thus, the directional response of the bottom hole assembly.
  • the rotation speed of the drilling string is used in achieving drill bit control.
  • FIG. 5 depicts a schematic representation of an embodiment of drilling string 292 with dual motors in bottom hole assembly 294 .
  • Drilling string 292 is coupled to bottom hole assembly 294 .
  • Bottom hole assembly 294 includes motor 296 A and motor 296 B.
  • Motor 296 A may be a bent sub and/or bent housing steerable mud motor.
  • Motor 296 A may drive drill bit 298 .
  • Motor 296 B may operate in a rotation direction that is opposite to the rotation of drilling string 292 and/or motor 296 A.
  • Motor 296 B may operate at a relatively low rotary speed and have high torque capacity as compared to motor 296 A.
  • Bottom hole assembly 294 may include sensing array 300 between motors 296 A, motor 296 B. Sensing array 300 may include a collar with various directional sensors and telemetry.
  • motor 296 B may rotate in a direction opposite to the rotation of drilling string 292 . In this manner, portions of bottom hole assembly 294 beyond motor 296 B may have less rotation in the direction of rotation of drilling string 292 .
  • motor 296 B is a reverse-rotation low speed motor.
  • the revolutions per minute (rpm) versus differential pressure relationship for bottom hole assembly 294 may be assessed prior to running drilling string 292 and the bottom hole assembly 294 in the formation to determine the differential pressure at neutral drilling speed (when the drilling string speed is equal and opposite to the speed of motor 296 B). Measured differential pressure may be used by a control system during drilling to control the speed of the drilling string relative to the neutral drilling speed.
  • motor 296 B is operated at a substantially fixed speed.
  • motor 296 B may be operated at a speed of 30 rpm. Other speeds may be used as desired.
  • a mud motor is installed in a bottom hole assembly in an inverted orientation (for example, upside-down from the normal orientation).
  • the inverted mud motor may be operated in a reverse direction of rotation relative to other mud motors, a drill bit, and/or a drilling string.
  • motor 296 B shown in FIG. 5 , may be installed in an inverted orientation to produce a relative counter-clockwise rotation in portions of bottom hole assembly 294 distal to motor 296 B (see counterclockwise arrow).
  • FIG. 6 depicts a schematic representation of an embodiment of drilling string 292 including motor 312 in bottom hole assembly 294 .
  • Motor 312 may be a low rpm, high torque motor that includes stator 302 , rotor 304 , and motor shaft 306 .
  • Motor shaft 306 couples to driveshaft 310 of drilling string 292 at connection 308 .
  • a bit box may be provided at the end of motor shaft 306 .
  • Motor shaft 306 and the bit box may face up-hole.
  • the bit box may be fixed relative to drilling string 292 .
  • Stator 302 may rotate counter-clockwise relative to drilling string 292 .
  • Installing a mud motor in an inverted orientation may allow for the use of off-the-shelf motors to produce counter-rotation and/or non-rotation of selected elements of the bottom hole assembly.
  • reactive torque from motor 296 A is transferred to motor 312 .
  • a threading kit is used (for example, at connection 308 ) to adapt a threaded mounting for the mud motor to ensure that a secure connection between an inverted mud motor and its mounting is maintained during drilling.
  • the threading kit may reverse the threads (for example, using left hand threads at connection 308 ).
  • the connection includes profile-matched sleeve and/or backoff-protected connection.
  • a tool for steerable drilling is at least 43 ⁇ 4 inches with about 25 rpm at 1500 ft-lbs when flowing at 250 gpm.
  • Such a system may be configured to produce at least 2000 ft-lb torque.
  • the rotation speed of drilling string 292 is used to control the trajectory of the wellbore being formed.
  • drilling string 292 may initially be rotating at 40 rpm, and motor 296 B rotates at 30 rpm.
  • the counter-rotation of motor 296 B and drilling string 292 results in a forward rotation speed (for example, an absolute forward rotation speed) of 10 rpm in the lower portion of bottom hole assembly 294 (the portion of the bottom hole assembly below motor 296 B).
  • a forward rotation speed for example, an absolute forward rotation speed
  • the speed of drilling string 292 is changed to the neutral drilling speed. Because drilling string 292 is rotating, there is no need to lift drill bit 298 off the bottom of the borehole. Operating at neutral drilling speed may effectively cancel the torque of the drilling string so that drill bit 298 is subjected to torque induced by motor 296 A and the formation.
  • One of the problems with existing slide drilling processes is that as the drilling string length increases, it may become more difficult to maintain a stable toolface setting due to torsional energy stored in the drilling string. This torsional energy may cause the drilling string to “wind-up” or store rotations. This wind-up may release unpredictably and cause the end of the drilling string to which the motor is attached to rotate independent of the drilling string at the surface.
  • the continuous rotation of drilling string 292 keeps windup of the drilling string consistent and stabilizes drill bit 298 .
  • Directional changes of drill bit 298 may be made by changing the speed of drilling string 292 .
  • Using a dual motor rotary steerable system allows the changing of the direction of the drilling string to occur while the drilling string rotates at or near the normal operating rotation speed of drilling string 292 .
  • FIG. 7 depicts cumulative time operating at a particular drilling string rotation speed and direction during drilling in conventional slide mode. Most of the time, the surface rpm is zero (for example, slide drilling) while some of the time the operator rotates the string forward or backward to influence the toolface position of the steerable mud motor downhole.
  • FIG. 8 depicts cumulative time at rotation speed during directional change for the dual motor drilling string during the drill bit direction change. Drill bit control may be substantially the same as for conventional slide mode drilling where torque/rotary adjustment is used to control the drill bit in the desired direction, but to the effect that 0 rpm on the x-axis of FIG. 7 becomes N (the neutral drilling string speed) in FIG. 8 .
  • connection of bottom hole assembly 294 to drilling string 292 of the dual motor rotary steerable system depicted in FIG. 5 may be subjected to the net effect of all the torque components required to rotate the entire bottom hole assembly (including torque generated at drill bit 298 during wellbore formation). Threaded connections along drilling string 292 may include profile-matched sleeves such as those known in the art for utilities drilling systems.
  • a control system used to control wellbore formation includes a system that sets a desired rotation speed of drilling string 292 when direction changes in trajectory of the wellbore are to be implemented.
  • the system may include fine tuning of the desired drilling string rotation speed.
  • the control system may be configured to assume full autonomous control over the wellbore trajectory during drilling.
  • drilling string 292 is integrated with position measurement and downhole tools (for example, sensing array 312 ) to autonomously control the hole path along a designed geometry.
  • An autonomous control system for controlling the path of drilling string 292 may utilize two or more domains of functionality.
  • a control system utilizes at least three domains of functionality including, but not limited to, measurement, trajectory, and control. Measurement may be made using sensor systems and/or other equipment hardware that assess angles, distances, magnetic fields, and/or other data. Trajectory may include flight path calculation and algorithms that utilize physical measurements to calculate angular and spatial offsets of the drilling string.
  • the control system may implement actions to keep the drilling string in the proper path.
  • the control system may include tools that utilize software/control interfaces built into an operating system of the drilling equipment, drilling string and/or bottom hole assembly.
  • control system utilizes position and angle measurements to define spatial and angular offsets from the desired drilling geometry.
  • the defined offsets may be used to determine a steering solution to move the trajectory of the drilling string (thus, the trajectory of the borehole) back into convergence with the desired drilling geometry.
  • the steering solution may be based on an optimum alignment solution in which a desired rate of curvature of the borehole path is set, and required angle change segments and angle change directions for the path are assessed (for example, by computation).
  • control system uses a fixed angle change rate associated with the drilling string, assesses the lengths of the sections of the drilling string, and assesses the desired directions of the drilling to autonomously execute and control movement of the drilling string.
  • control system assesses position measurements and controls of the drilling string to control the direction of the drilling string.
  • differential pressure or torque across motor 296 A and/or motor 296 B is used to control the rate of penetration.
  • a relationship between rate of penetration, weight-on-bit, and torque may be assessed for drilling string 292 .
  • Measurements of torque and the rate of penetration/weight-on-bit/torque relationship may be used to control the feed rate of drilling string 292 into the formation.
  • Accuracy and efficiency in forming wellbores in subsurface formations may be affected by the density and quality of directional data during drilling.
  • the quality of directional data may be diminished by vibrations and angular accelerations during rotary drilling, especially during rotary drilling segments of wellbore formation using slide mode drilling.
  • FIG. 9 depicts an embodiment of drilling string 292 with non-rotating sensor 314 .
  • Non-rotating sensor 314 is located behind motor 296 .
  • Motor 296 may be a steerable motor.
  • Motor 296 is located behind drill bit 298 .
  • sensor 314 is located between non-magnetic components in drilling string 292 .
  • non-rotating sensor 314 is located in a sleeve over motor 296 . In some embodiments, non-rotating sensor 314 is run on a bottom hole assembly for improved data assessment. In an embodiment, a non-rotating sensor is coupled to and/or driven by a motor that produces relative counter-rotation of the sensor relative to other components of the bottom hole assembly. For example, a sensor may be coupled to the motor having a rotation speed equal and opposite to that of the bottom hole assembly housing to which it is attached so that the absolute rotation speed of the sensor is or is substantially zero. In certain embodiments, the motor for a sensor is a mud motor installed in an inverted orientation such as described above relative to FIG. 5 .
  • non-rotating sensor 314 includes one or more transceivers for communicating data either into drilling string 292 within the bottom hole assembly or to similar transceivers in nearby boreholes.
  • the transceivers may be used for telemetry of data and/or as a means of position assessment or verification.
  • use of non-rotating sensor 314 is used for continuous position measurement. Continuous position measurement may be useful in control systems used for drilling position systems and/or umbilical position control.
  • continuous magnetic ranging is possible using the embodiments depicted in FIG. 9 .
  • continuous magnetic ranging may include embodiments described herein such as where a reference magnetic field is generated by passing current through one or more heaters, conductors, and/or casing in adjacent holes/wells.
  • an automatic position control system in combination with a rack and pinion drilling system may be used for forming wellbores in a formation.
  • Use of an automatic position control and/or measurement system in combination with a rack and pinion drilling system may allow wellbores to be drilled more accurately than drilling using manual positioning and calibration.
  • the automatic position system may be continuously and/or semi-continuously calibrated during drilling.
  • FIG. 10 depicts a schematic of a portion of a system including a rack and pinion drive system.
  • Rack and pinion drive system 316 includes, but is not limited to, rack 318 , carriage 320 , chuck drive system 322 , and circulating sleeve 324 .
  • Chuck drive system 322 may hold tubular 326 .
  • Push/pull capacity of a rack and pinion type system may allow enough force (for example, about 5 tons) to push tubulars into wellbores so that rotation of the tubulars is not necessary.
  • a rack and pinion system may apply downward force on the drill bit.
  • the force applied to the drill bit may be independent of the weight of the drilling string (tubulars) and/or collars. In certain embodiments, collar size and weight is reduced because the weight of the collars is not needed to enable drilling operations.
  • Drilling wellbores with long horizontal portions may be performed using rack and pinion drilling systems because of the ability of the drilling systems to apply force to the drilling bit independent of the vertical length of drill string available to provide weight on bit.
  • Rack and pinion drive system 316 may be coupled to automatic position control system 328 .
  • Automatic position control system 328 may include, but is not limited to, rotary steerable systems, dual motor rotary steerable systems, and/or hole measurement systems.
  • a measurement system includes one or more sensors, including, but not limited to, magnetic ranging sensors, non-rotating sensors, and/or canted accelerometers.
  • one or more heaters are included in one or more tubulars of the rack and pinion drive system.
  • hole measurement systems are positioned in the heaters.
  • a hole measuring system includes one or more canted accelerometers.
  • Use of canted accelerometers may allow for surveying of a shallow portion of the formation.
  • shallow portions of the formation may have steel casing strings from drilling operations and/or other wells.
  • the steel casings may affect the use of magnetic survey tools in determining the direction of deflection incurred during drilling.
  • Canted accelerometers may be positioned in a bottom hole assembly of a drilling system (for example, a rack and pinion drilling system) with the surface as reference of tubular rotational position. Positioning the canted accelerometers in a bottom hole assembly may allow accurate measurement of inclination and direction of a hole regardless of the influence of nearby magnetic interference sources (for example, casing strings).
  • the relative rotational position of the tubular is monitored by measuring and tracking incremental rotation of the shaft.
  • a method of drilling using a rack and pinion system includes continuous downhole measurement.
  • a measurement system may be operated using a predetermined and constant current signal.
  • Distance and direction are calculated continuously downhole.
  • the results of the calculations are filtered and averaged.
  • a best estimate final distance and direction is reported to the surface.
  • the known along-hole depth and tubular location may be combined with the calculated distance and direction to calculate X, Y and Z position data.
  • a drilling sequence is used in which tubulars are added to a string without interrupting the drilling process.
  • the tubulars may include jointed connections that allow the tubulars to be connected under pressure. Such a sequence may allow continuous rotary drilling with large diameter tubulars.
  • the tubulars may include heaters and/or automatic position control systems described herein.
  • a continuous rotary drilling system may include a drilling platform, which includes, but is not limited to, one or more platforms, a top drive system, and a bottom drive system.
  • the platform may include a rack to allow multiple independent traversing of components.
  • the top drive system may include an extended drive sub (for example, an extended drive system manufactured by American Augers, West Salem, Ohio, U.S.A.).
  • the top drive system may be, for example, a rotary drive system or a rack and pinion drive system.
  • the bottom drive system may include a chuck drive system and a hydraulic system.
  • the bottom drive system may operate in a similar manner to a rack and pinion drilling system (for example, the rack and pinion system described in FIG. 10 ).
  • Bottom drive system and top drive system may alternate control of the drilling operation.
  • the chuck drive system may be mounted on a separate carriage.
  • the hydraulic system may include, but is not limited to, one or more motors and a circulating sleeve.
  • the circulating sleeve may allow circulation between tubulars and the annulus.
  • the circulating sleeve may be used to open or shut off production from various intervals in the well.
  • a system includes a tubular handling system.
  • a tubular handling system may be automated, manually operated, or a combination thereof.
  • a method using a continuous rotary drilling system includes adding a new tubular to an existing tubular coupled to a bottom drive system to form an extended tubular.
  • a new tubular may be positioned in an opening of the circulating sleeve of the bottom drive system.
  • the new tubular may be coupled to a top drive system.
  • the circulating sleeve of the bottom drive system may allow fluid to flow around the two tubulars.
  • the fluid pressure in the circulating sleeve may be at pressures of up to about 13.8 MPa (2000 psi).
  • the circulation sleeve may include one or more valves (for example, UBD circulation or check valves) that facilitate change and/or flow of circulation.
  • valves may assist in maintaining pressure in the system.
  • the pressure applied to the two tubulars in the circulating sleeve may couple (for example, pressure-fit) the two tubulars to form a coupled tubular without interruption of the drilling process.
  • control of the drilling operation may be transferred from the bottom drive system to the top drive system. Transfer of the drilling operation to the top drive system may allow the bottom drive system to travel up the coupled tubular towards the top drive system without interruption of the drilling process.
  • the bottom drive system may attach to a drive sub of the top drive system and the control of the drilling operation may be transferred from the top drive system to the bottom drive system without interruption of the drilling process.
  • the top drive system may disconnect from the tubular. The top drive system may then connect to the top of another tubular to continue the process.
  • FIGS. 11A-11D depict a schematic of an embodiment of a continuous drilling sequence.
  • FIG. 12 depicts a cut-away view of an embodiment of a circulating sleeve of the bottom drive system depicted in FIGS. 11A-11D .
  • FIG. 13 depicts a schematic of the valve system of the circulating sleeve of the bottom drive system depicted in FIGS. 11A-11D .
  • the continuous drilling sequence includes bottom (rack and pinion) drive system 316 , tubular handling system 330 , and top drive system 332 .
  • Top drive system 332 includes top circulating sleeve 334 and drive sub 336 .
  • Bottom drive system 316 includes bottom circulating sleeve 324 and chuck 322 .
  • the chuck may be on a separate carriage system.
  • top drive system 332 is at reference line Y and bottom drive system 316 is at reference line Z. It will be understood that reference lines Y and Z are shown for illustrative purposes only, and the heights of the drive systems at various stages in the sequence may be different than those depicted in FIGS. 11A-11D .
  • bottom drive system controls the drilling operation that inserts existing tubular 326 in a subsurface formation.
  • fluid may enter bottom circulating sleeve 324 through port 346 and flow around existing tubular 326 . Fluid may remove heat away from chuck 322 and/or existing tubular 326 .
  • Bottom circulating sleeve 324 may include side valve 338 (shown in FIG. 13 ).
  • Side valve 338 may be a check valve incorporated into a side entry flow and check valve port.
  • Use of side valve 338 and/or top valve 348 (shown in FIG. 13 ) may facilitate change of circulation entry points and creation of a pressurized system (for example, pressures up to about 13.8 MPa).
  • new tubular 340 may be aligned with bottom drive system 316 using tubular handling system 330 .
  • top drive system 332 may be connected to a top end (for example, a box end) of new tubular 340 .
  • top drive system 332 lowers and positions or drops a bottom end of new tubular 340 in opening 344 (depicted in FIG. 12 ) of circulating sleeve 324 of bottom drive system 316 .
  • bottom circulating sleeve 324 includes side valve 338 (shown in FIG.
  • bottom circulating sleeve 324 may include, and/or operate in conjunction with, one or more valves.
  • Opening 344 may include one or more tooljoints 350 (see FIG. 12 ).
  • Tooljoints 350 may guide entry of new tubular 340 in an inner section of circulating sleeve. Since circulating sleeve 324 is pressurized, tooljoints 350 may allow equalization of pressure in the sleeve. Equalization of the pressure facilitates moving new tubular 340 past top entry valve 348 and into bottom circulating sleeve 324 .
  • Coupled tubular 354 includes new tubular 340 and existing tubular 326 .
  • chuck 322 of bottom drive system 316 may disconnect from coupled tubular 354 , thus relinquishing control of the drilling process to top drive system 332 .
  • bottom drive system 316 may be actuated to travel upward (see arrow shown in FIG. 11C ) toward top drive system 332 along the length of coupled tubular 354 .
  • bottom circulating system sleeve 324 of bottom drive system 316 comes into proximity with drive sub 336 of top drive system 332 , fluid from top drive system 332 may be flowing from top circulating sleeve 334 of top drive system 332 through top valve 348 (shown in FIG. 13 ).
  • Bottom circulating sleeve 324 may be pressurized and side valve 338 (shown in FIG. 13 ) may open to provide flow.
  • Top valve 348 (shown in FIG.
  • top valve 348 may close completely and all fluid may be furnished through side valve 338 from port 346 .
  • bottom drive system 316 may engage drive sub 336 .
  • Coupled tubular 354 may disengage from drive sub 336 and engage with chuck 322 while bottom drive system 316 resumes control of the drilling operation. Chuck 322 transfers force to couple tubular 354 to continue the drilling process.
  • top drive system 332 may be raised (see up arrow) relative to bottom drive system 316 (for example, until top drive system 332 reaches reference line Y as shown in FIG. 11D ).
  • Bottom drive system 316 may be lowered to push coupled tubular 354 downward into the formation (see down arrows in FIG. 11D ).
  • Bottom drive system 316 may continue to be lowered (for example, until bottom drive system 316 has returned to reference line Z). The sequence described above may be repeated any number of times so as to maintain continuous drilling operations.
  • Some wellbores formed in the formation may be used to facilitate formation of a perimeter barrier around a treatment area.
  • Heat sources in the treatment area may heat hydrocarbons in the formation within the treatment area.
  • the perimeter barrier may be, but is not limited to, a low temperature or frozen barrier formed by freeze wells, a wax barrier formed in the formation, dewatering wells, a grout wall formed in the formation, a sulfur cement barrier, a barrier formed by a gel produced in the formation, a barrier formed by precipitation of salts in the formation, a barrier formed by a polymerization reaction in the formation, and/or sheets driven into the formation.
  • Heat sources, production wells, injection wells, dewatering wells, and/or monitoring wells may be installed in the treatment area defined by the barrier prior to, simultaneously with, or after installation of the barrier.
  • a low temperature zone around at least a portion of a treatment area may be formed by freeze wells.
  • refrigerant is circulated through freeze wells to form low temperature zones around each freeze well.
  • the freeze wells are placed in the formation so that the low temperature zones overlap and form a low temperature zone around the treatment area.
  • the low temperature zone established by freeze wells is maintained below the freezing temperature of aqueous fluid in the formation.
  • Aqueous fluid entering the low temperature zone freezes and forms the frozen barrier.
  • the freeze barrier is formed by batch operated freeze wells.
  • a cold fluid, such as liquid nitrogen, is introduced into the freeze wells to form low temperature zones around the freeze wells. The fluid is replenished as needed.
  • Grout, wax, polymer or other material may be used in combination with freeze wells to provide a barrier for the in situ heat treatment process.
  • the material may fill cavities (vugs) in the formation and reduces the permeability of the formation.
  • the material may have higher thermal conductivity than gas and/or formation fluid that fills cavities in the formation. Placing material in the cavities may allow for faster low temperature zone formation.
  • the material may form a perpetual barrier in the formation that may strengthen the formation.
  • the use of material to form the barrier in unconsolidated or substantially unconsolidated formation material may allow for larger well spacing than is possible without the use of the material.
  • the combination of the material and the low temperature zone formed by freeze wells may constitute a double barrier for environmental regulation purposes.
  • the material is introduced into the formation as a liquid, and the liquid sets in the formation to form a solid.
  • the material may be, but is not limited to, fine cement, micro fine cement, sulfur, sulfur cement, viscous thermoplastics, and/or waxes.
  • the material may include surfactants, stabilizers or other chemicals that modify the properties of the material. For example, the presence of surfactant in the material may promote entry of the material into small openings in the formation.
  • Material may be introduced into the formation through freeze well wellbores.
  • the material may be allowed to set.
  • the integrity of the wall formed by the material may be checked.
  • the integrity of the material wall may be checked by logging techniques and/or by hydrostatic testing. If the permeability of a section formed by the material is too high, additional material may be introduced into the formation through freeze well wellbores. After the permeability of the section is sufficiently reduced, freeze wells may be installed in the freeze well wellbores.
  • Material may be injected into the formation at a pressure that is high, but below the fracture pressure of the formation. In some embodiments, injection of material is performed in 16 m increments in the freeze wellbore. Larger or smaller increments may be used if desired. In some embodiments, material is only applied to certain portions of the formation. For example, material may be applied to the formation through the freeze wellbore only adjacent to aquifer zones and/or to relatively high permeability zones (for example, zones with a permeability greater than about 0.1 darcy). Applying material to aquifers may inhibit migration of water from one aquifer to a different aquifer. For material placed in the formation through freeze well wellbores, the material may inhibit water migration between aquifers during formation of the low temperature zone. The material may also inhibit water migration between aquifers when an established low temperature zone is allowed to thaw.
  • the material used to form a barrier may be fine cement and micro fine cement.
  • Cement may provide structural support in the formation.
  • Fine cement may be ASTM type 3 Portland cement. Fine cement may be less expensive than micro fine cement.
  • a freeze wellbore is formed in the formation. Selected portions of the freeze wellbore are grouted using fine cement. Then, micro fine cement is injected into the formation through the freeze wellbore. The fine cement may reduce the permeability down to about 10 millidarcy. The micro fine cement may further reduce the permeability to about 0.1 millidarcy. After the grout is introduced into the formation, a freeze wellbore canister may be inserted into the formation. The process may be repeated for each freeze well that will be used to form the barrier.
  • fine cement is introduced into every other freeze wellbore.
  • Micro fine cement is introduced into the remaining wellbores.
  • grout may be used in a formation with freeze wellbores set at about 5 m spacing.
  • a first wellbore is drilled and fine cement is introduced into the formation through the wellbore.
  • a freeze well canister is positioned in the first wellbore.
  • a second wellbore is drilled 10 m away from the first wellbore.
  • Fine cement is introduced into the formation through the second wellbore.
  • a freeze well canister is positioned in the second wellbore.
  • a third wellbore is drilled between the first wellbore and the second wellbore.
  • grout from the first and/or second wellbores may be detected in the cuttings of the third wellbore.
  • Micro fine cement is introduced into the formation through the third wellbore.
  • a freeze wellbore canister is positioned in the third wellbore. The same procedure is used to form the remaining freeze wells that will form the barrier around the treatment area.
  • Fiber optic temperature monitoring systems may also be used to monitor temperatures in heated portions of the formation during in situ heat treatment processes. Temperature monitoring systems positioned in production wells, heater wells, injection wells, and/or monitor wells may be used to measure temperature profiles in treatment areas subjected to in situ heat treatment processes.
  • the fiber of a fiber optic cable used in the heated portion of the formation may be clad with a reflective material to facilitate retention of a signal or signals transmitted down the fiber.
  • the fiber is clad with gold, copper, nickel, aluminum and/or alloys thereof.
  • the cladding may be formed of a material that is able to withstand chemical and temperature conditions in the heated portion of the formation. For example, gold cladding may allow an optical sensor to be used up to temperatures of 700° C.
  • the fiber is clad with aluminum.
  • the fiber may be dipped in or run through a bath of liquid aluminum.
  • the clad fiber may then be allowed to cool to secure the aluminum to the fiber.
  • the gold or aluminum cladding may reduce hydrogen darkening of the optical fiber.
  • two or more rows of freeze wells are located about all or a portion of the perimeter of the treatment area to form a thick interconnected low temperature zone. Thick low temperature zones may be formed adjacent to areas in the formation where there is a high flow rate of aqueous fluid in the formation. The thick barrier may ensure that breakthrough of the frozen barrier established by the freeze wells does not occur.
  • a double barrier system is used to isolate a treatment area.
  • the double barrier system may be formed with a first barrier and a second barrier.
  • the first barrier may be formed around at least a portion of the treatment area to inhibit fluid from entering or exiting the treatment area.
  • the second barrier may be formed around at least a portion of the first barrier to isolate an inter-barrier zone between the first barrier and the second barrier.
  • the inter-barrier zone may have a thickness from about 1 m to about 300 m. In some embodiments, the thickness of the inter-barrier zone is from about 10 m to about 100 m, or from about 20 m to about 50 m.
  • the double barrier system may allow greater project depths than a single barrier system. Greater depths are possible with the double barrier system because the stepped differential pressures across the first barrier and the second barrier is less than the differential pressure across a single barrier. The smaller differential pressures across the first barrier and the second barrier make a breach of the double barrier system less likely to occur at depth for the double barrier system as compared to the single barrier system.
  • additional barriers may be positioned to connect the inner barrier to the outer barrier. The additional barriers may further strengthen the double barrier system and define compartments that limit the amount of fluid that can pass from the inter-barrier zone to the treatment area should a breach occur in the first barrier.
  • the first barrier and the second barrier may be the same type of barrier or different types of barriers.
  • the first barrier and the second barrier are formed by freeze wells.
  • the first barrier is formed by freeze wells
  • the second barrier is a grout wall.
  • the grout wall may be formed of cement, sulfur, sulfur cement, or combinations thereof.
  • a portion of the first barrier and/or a portion of the second barrier is a natural barrier, such as an impermeable rock formation.
  • one or both barriers may be formed from wellbores positioned in the formation.
  • the position of the wellbores used to form the second barrier may be adjusted relative to the wellbores used to form the first barrier to limit a separation distance between a breach or portion of the barrier that is difficult to form and the nearest wellbore.
  • the position of the freeze wells may be adjusted to facilitate formation of the barriers and limit the distance between a potential breach and the closest wells to the breach.
  • Adjusting the position of the wells of the second barrier relative to the wells of the first barrier may also be used when one or more of the barriers are barriers other than freeze barriers (for example, dewatering wells, cement barriers, grout barriers, and/or wax barriers).
  • wellbores for forming the first barrier are formed in a row in the formation.
  • logging techniques and/or analysis of cores may be used to determine the principal fracture direction and/or the direction of water flow in one or more layers of the formation.
  • two or more layers of the formation may have different principal fracture directions and/or the directions of water flow that need to be addressed.
  • three or more barriers may need to be formed in the formation to allow for formation of the barriers that inhibit inflow of formation fluid into the treatment area or outflow of formation fluid from the treatment area. Barriers may be formed to isolate particular layers in the formation.
  • the principal fracture direction and/or the direction of water flow may be used to determine the placement of wells used to form the second barrier relative to the wells used to form the first barrier.
  • the placement of the wells may facilitate formation of the first barrier and the second barrier.
  • FIG. 14 depicts a schematic representation of barrier wells 200 used to form a first barrier and barrier wells 200 ′ used to form a second barrier when the principal fracture direction and/or the direction of water flow is at angle A relative to the first barrier.
  • the principal fracture direction and/or direction of water flow is indicated by arrow 356 .
  • the case where angle A is 0 is the case where the principal fracture direction and/or the direction of water flow is substantially normal to the barriers.
  • Spacing between two adjacent barrier wells 200 of the first barrier or between barrier wells 200 ′ of the second barrier are indicated by distance s.
  • the spacing s may be 2 m, 3 m, 10 m or greater.
  • Distance d indicates the separation distance between the first barrier and the second barrier. Distance d may be less than s, equal to s, or greater than s.
  • Barrier wells 200 ′ of the second barrier may have offset distance od relative to barrier wells 200 of the first barrier. Offset distance od may be calculated by the equation:
  • Using the od according to EQN. 1 maintains a maximum separation distance of s/4 between a barrier well and a regular fracture extending between the barriers. Having a maximum separation distance of s/4 by adjusting the offset distance based on the principal fracture direction and/or the direction of water flow may enhance formation of the first barrier and/or second barrier. Having a maximum separation distance of s/4 by adjusting the offset distance of wells of the second barrier relative to the wells of the first barrier based on the principal fracture direction and/or the direction of water flow may reduce the time needed to reform the first barrier and/or the second barrier should a breach of the first barrier and/or the second barrier occur.
  • od may be set at a value between the value generated by EQN. 1 and the worst case value.
  • the worst case value of od may be if barrier wells 200 of the first freeze barrier and barrier wells 200 ′ of the second barrier are located along the principal fracture direction and/or direction of water flow (i.e., along arrow 356 ). In such a case, the maximum separation distance would be s/2. Having a maximum separation distance of s/2 may slow the time needed to form the first barrier and/or the second barrier, or may inhibit formation of the barriers.
  • the barrier wells for the treatment area are freeze wells.
  • Vertically positioned freeze wells and/or horizontally positioned freeze wells may be positioned around sides of the treatment area. If the upper layer (the overburden) or the lower layer (the underburden) of the formation is likely to allow fluid flow into the treatment area or out of the treatment area, horizontally positioned freeze wells may be used to form an upper and/or a lower barrier for the treatment area.
  • an upper barrier and/or a lower barrier may not be necessary if the upper layer and/or the lower layer are at least substantially impermeable.
  • portions of heat sources, production wells, injection wells, and/or dewatering wells that pass through the low temperature zone created by the freeze wells forming the upper freeze barrier wells may be insulated and/or heat traced so that the low temperature zone does not adversely affect the functioning of the heat sources, production wells, injection wells and/or dewatering wells passing through the low temperature zone.
  • In situ heat treatment processes and solution mining processes may heat the treatment area, remove mass from the treatment area, and greatly increase the permeability of the treatment area.
  • the treatment area after being treated may have a permeability of at least 0.1 darcy.
  • the treatment area after being treated has a permeability of at least 1 darcy, of at least 10 darcy, or of at least 100 darcy.
  • the increased permeability allows the fluid to spread in the formation into fractures, microfractures, and/or pore spaces in the formation. Outside of the treatment area, the permeability may remain at the initial permeability of the formation. The increased permeability allows fluid introduced to flow easily within the formation.
  • a barrier may be formed in the formation after a solution mining process and/or an in situ heat treatment process by introducing a fluid into the formation.
  • the barrier may inhibit formation fluid from entering the treatment area after the solution mining and/or in situ heat treatment processes have ended.
  • the barrier formed by introducing fluid into the formation may allow for isolation of the treatment area.
  • the fluid introduced into the formation to form a barrier may include wax, bitumen, heavy oil, sulfur, polymer, gel, saturated saline solution, and/or one or more reactants that react to form a precipitate, solid or high viscosity fluid in the formation.
  • bitumen, heavy oil, reactants and/or sulfur used to form the barrier are obtained from treatment facilities associated with the in situ heat treatment process.
  • sulfur may be obtained from a Claus process used to treat produced gases to remove hydrogen sulfide and other sulfur compounds.
  • the fluid may be introduced into the formation as a liquid, vapor, or mixed phase fluid.
  • the fluid may be introduced into a portion of the formation that is at an elevated temperature.
  • the fluid is introduced into the formation through wells located near a perimeter of the treatment area.
  • the fluid may be directed away from the treatment area.
  • the elevated temperature of the formation maintains or allows the fluid to have a low viscosity so that the fluid moves away from the wells.
  • a portion of the fluid may spread outwards in the formation towards a cooler portion of the formation.
  • the relatively high permeability of the formation allows fluid introduced from one wellbore to spread and mix with fluid introduced from other wellbores. In the cooler portion of the formation, the viscosity of the fluid increases, a portion of the fluid precipitates, and/or the fluid solidifies or thickens so that the fluid forms the barrier to flow of formation fluid into or out of the treatment area.
  • a low temperature barrier formed by freeze wells surrounds all or a portion of the treatment area.
  • the temperature of the formation becomes colder.
  • the colder temperature increases the viscosity of the fluid, enhances precipitation, and/or solidifies the fluid to form the barrier to the flow of formation fluid into or out of the formation.
  • the fluid may remain in the formation as a highly viscous fluid or a solid after the low temperature barrier has dissipated.
  • saturated saline solution is introduced into the formation.
  • Components in the saturated saline solution may precipitate out of solution when the solution reaches a colder temperature.
  • the solidified particles may form the barrier to the flow of formation fluid into or out of the formation.
  • the solidified components may be substantially insoluble in formation fluid.
  • a potential source of heat loss from the heated formation is due to reflux in wells. Refluxing occurs when vapors condense in a well and flow into a portion of the well adjacent to the heated portion of the formation. Vapors may condense in the well adjacent to the overburden of the formation to form condensed fluid. Condensed fluid flowing into the well adjacent to the heated formation absorbs heat from the formation. Heat absorbed by condensed fluids cools the formation and necessitates additional energy input into the formation to maintain the formation at a desired temperature. Some fluids that condense in the overburden and flow into the portion of the well adjacent to the heated formation may react to produce undesired compounds and/or coke. Inhibiting fluids from refluxing may significantly improve the thermal efficiency of the in situ heat treatment system and/or the quality of the product produced from the in situ heat treatment system.
  • the portion of the well adjacent to the overburden section of the formation is cemented to the formation.
  • the well includes packing material placed near the transition from the heated section of the formation to the overburden. The packing material inhibits formation fluid from passing from the heated section of the formation into the section of the wellbore adjacent to the overburden. Cables, conduits, devices, and/or instruments may pass through the packing material, but the packing material inhibits formation fluid from passing up the wellbore adjacent to the overburden section of the formation.
  • one or more baffle systems may be placed in the wellbores to inhibit reflux.
  • the baffle systems may be obstructions to fluid flow into the heated portion of the formation.
  • refluxing fluid may revaporize on the baffle system before coming into contact with the heated portion of the formation.
  • a gas may be introduced into the formation through wellbores to inhibit reflux in the wellbores.
  • gas may be introduced into wellbores that include baffle systems to inhibit reflux of fluid in the wellbores.
  • the gas may be carbon dioxide, methane, nitrogen or other desired gas.
  • the introduction of gas may be used in conjunction with one or more baffle systems in the wellbores. The introduced gas may enhance heat exchange at the baffle systems to help maintain top portions of the baffle systems colder than the lower portions of the baffle systems.
  • the flow of production fluid up the well to the surface is desired for some types of wells, especially for production wells. Flow of production fluid up the well is also desirable for some heater wells that are used to control pressure in the formation.
  • the overburden, or a conduit in the well used to transport formation fluid from the heated portion of the formation to the surface may be heated to inhibit condensation on or in the conduit. Providing heat in the overburden, however, may be costly and/or may lead to increased cracking or coking of formation fluid as the formation fluid is being produced from the formation.
  • one or more diverters may be placed in the wellbore to inhibit fluid from refluxing into the wellbore adjacent to the heated portion of the formation.
  • the diverter retains fluid above the heated portion of the formation. Fluids retained in the diverter may be removed from the diverter using a pump, gas lifting, and/or other fluid removal technique.
  • two or more diverters that retain fluid above the heated portion of the formation may be located in the production well. Two or more diverters provide a simple way of separating initial fractions of condensed fluid produced from the in situ heat treatment system.
  • a pump may be placed in each of the diverters to remove condensed fluid from the diverters.
  • the diverter directs fluid to a sump below the heated portion of the formation.
  • An inlet for a lift system may be located in the sump.
  • the intake of the lift system is located in casing in the sump.
  • the intake of the lift system is located in an open wellbore.
  • the sump is below the heated portion of the formation.
  • the intake of the pump may be located 1 m, 5 m, 10 m, 20 m or more below the deepest heater used to heat the heated portion of the formation.
  • the sump may be at a cooler temperature than the heated portion of the formation.
  • the sump may be more than 10° C., more than 50° C., more than 75° C., or more than 100° C. below the temperature of the heated portion of the formation.
  • a portion of the fluid entering the sump may be liquid.
  • a portion of the fluid entering the sump may condense within the sump.
  • the lift system moves the fluid in the sump to the surface.
  • Production well lift systems may be used to efficiently transport formation fluid from the bottom of the production wells to the surface.
  • Production well lift systems may provide and maintain the maximum required well drawdown (minimum reservoir producing pressure) and producing rates.
  • the production well lift systems may operate efficiently over a wide range of high temperature/multiphase fluids (gas/vapor/steam/water/hydrocarbon liquids) and production rates expected during the life of a typical project.
  • Production well lift systems may include dual concentric rod pump lift systems, chamber lift systems and other types of lift systems.
  • Temperature limited heaters may be in configurations and/or may include materials that provide automatic temperature limiting properties for the heater at certain temperatures.
  • ferromagnetic materials are used in temperature limited heaters. Ferromagnetic material may self-limit temperature at or near the Curie temperature of the material and/or the phase transformation temperature range to provide a reduced amount of heat when a time-varying current is applied to the material.
  • the ferromagnetic material self-limits temperature of the temperature limited heater at a selected temperature that is approximately the Curie temperature and/or in the phase transformation temperature range. In certain embodiments, the selected temperature is within about 35° C., within about 25° C., within about 20° C., or within about 10° C.
  • ferromagnetic materials are coupled with other materials (for example, highly conductive materials, high strength materials, corrosion resistant materials, or combinations thereof) to provide various electrical and/or mechanical properties.
  • Some parts of the temperature limited heater may have a lower resistance (caused by different geometries and/or by using different ferromagnetic and/or non-ferromagnetic materials) than other parts of the temperature limited heater. Having parts of the temperature limited heater with various materials and/or dimensions allows for tailoring the desired heat output from each part of the heater.
  • Temperature limited heaters may be more reliable than other heaters. Temperature limited heaters may be less apt to break down or fail due to hot spots in the formation. In some embodiments, temperature limited heaters allow for substantially uniform heating of the formation. In some embodiments, temperature limited heaters are able to heat the formation more efficiently by operating at a higher average heat output along the entire length of the heater. The temperature limited heater operates at the higher average heat output along the entire length of the heater because power to the heater does not have to be reduced to the entire heater, as is the case with typical constant wattage heaters, if a temperature along any point of the heater exceeds, or is about to exceed, a maximum operating temperature of the heater.
  • Heat output from portions of a temperature limited heater approaching a Curie temperature and/or the phase transformation temperature range of the heater automatically reduces without controlled adjustment of the time-varying current applied to the heater.
  • the heat output automatically reduces due to changes in electrical properties (for example, electrical resistance) of portions of the temperature limited heater. Thus, more power is supplied by the temperature limited heater during a greater portion of a heating process.
  • the system including temperature limited heaters initially provides a first heat output and then provides a reduced (second heat output) heat output, near, at, or above the Curie temperature and/or the phase transformation temperature range of an electrically resistive portion of the heater when the temperature limited heater is energized by a time-varying current.
  • the first heat output is the heat output at temperatures below which the temperature limited heater begins to self-limit. In some embodiments, the first heat output is the heat output at a temperature about 50° C., about 75° C., about 100° C., or about 125° C. below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic material in the temperature limited heater.
  • the temperature limited heater may be energized by time-varying current (alternating current or modulated direct current) supplied at the wellhead.
  • the wellhead may include a power source and other components (for example, modulation components, transformers, and/or capacitors) used in supplying power to the temperature limited heater.
  • the temperature limited heater may be one of many heaters used to heat a portion of the formation.
  • the temperature limited heater includes a conductor that operates as a skin effect or proximity effect heater when time-varying current is applied to the conductor.
  • the skin effect limits the depth of current penetration into the interior of the conductor.
  • the skin effect is dominated by the magnetic permeability of the conductor.
  • the relative magnetic permeability of ferromagnetic materials is typically between 10 and 1000 (for example, the relative magnetic permeability of ferromagnetic materials is typically at least 10 and may be at least 50, 100, 500, 1000 or greater).
  • the magnetic permeability of the ferromagnetic material decreases substantially and the skin depth expands rapidly (for example, the skin depth expands as the inverse square root of the magnetic permeability).
  • the reduction in magnetic permeability results in a decrease in the AC or modulated DC resistance of the conductor near, at, or above the Curie temperature, the phase transformation temperature range, and/or as the applied electrical current is increased.
  • portions of the heater that approach, reach, or are above the Curie temperature and/or the phase transformation temperature range may have reduced heat dissipation. Sections of the temperature limited heater that are not at or near the Curie temperature and/or the phase transformation temperature range may be dominated by skin effect heating that allows the heater to have high heat dissipation due to a higher resistive load.
  • Curie temperature heaters have been used in soldering equipment, heaters for medical applications, and heating elements for ovens (for example, pizza ovens). Some of these uses are disclosed in U.S. Pat. No. 5,579,575 to Lamome et al.; U.S. Pat. No. 5,065,501 to Henschen et al.; and U.S. Pat. No. 5,512,732 to Yagnik et al., all of which are incorporated by reference as if fully set forth herein. U.S. Pat. No.
  • An advantage of using the temperature limited heater to heat hydrocarbons in the formation is that the conductor is chosen to have a Curie temperature and/or a phase transformation temperature range in a desired range of temperature operation. Operation within the desired operating temperature range allows substantial heat injection into the formation while maintaining the temperature of the temperature limited heater, and other equipment, below design limit temperatures. Design limit temperatures are temperatures at which properties such as corrosion, creep, and/or deformation are adversely affected. The temperature limiting properties of the temperature limited heater inhibit overheating or burnout of the heater adjacent to low thermal conductivity “hot spots” in the formation.
  • the temperature limited heater is able to lower or control heat output and/or withstand heat at temperatures above 25° C., 37° C., 100° C., 250° C., 500° C., 700° C., 800° C., 900° C., or higher up to 1131° C., depending on the materials used in the heater.
  • the temperature limited heater allows for more heat injection into the formation than constant wattage heaters because the energy input into the temperature limited heater does not have to be limited to accommodate low thermal conductivity regions adjacent to the heater. For example, in Green River oil shale there is a difference of at least a factor of 3 in the thermal conductivity of the lowest richness oil shale layers and the highest richness oil shale layers. When heating such a formation, substantially more heat is transferred to the formation with the temperature limited heater than with the conventional heater that is limited by the temperature at low thermal conductivity layers. The heat output along the entire length of the conventional heater needs to accommodate the low thermal conductivity layers so that the heater does not overheat at the low thermal conductivity layers and burn out.
  • the heat output adjacent to the low thermal conductivity layers that are at high temperature will reduce for the temperature limited heater, but the remaining portions of the temperature limited heater that are not at high temperature will still provide high heat output.
  • heaters for heating hydrocarbon formations typically have long lengths (for example, at least 10 m, 100 m, 300 m, 500 m, 1 km or more up to about 10 km)
  • the majority of the length of the temperature limited heater may be operating below the Curie temperature and/or the phase transformation temperature range while only a few portions are at or near the Curie temperature and/or the phase transformation temperature range of the temperature limited heater.
  • temperature limited heaters allows for efficient transfer of heat to the formation. Efficient transfer of heat allows for reduction in time needed to heat the formation to a desired temperature. For example, in Green River oil shale, pyrolysis typically requires 9.5 years to 10 years of heating when using a 12 m heater well spacing with conventional constant wattage heaters. For the same heater spacing, temperature limited heaters may allow a larger average heat output while maintaining heater equipment temperatures below equipment design limit temperatures. Pyrolysis in the formation may occur at an earlier time with the larger average heat output provided by temperature limited heaters than the lower average heat output provided by constant wattage heaters. For example, in Green River oil shale, pyrolysis may occur in 5 years using temperature limited heaters with a 12 m heater well spacing.
  • Temperature limited heaters counteract hot spots due to inaccurate well spacing or drilling where heater wells come too close together.
  • temperature limited heaters allow for increased power output over time for heater wells that have been spaced too far apart, or limit power output for heater wells that are spaced too close together. Temperature limited heaters also supply more power in regions adjacent the overburden and underburden to compensate for temperature losses in these regions.
  • Temperature limited heaters may be advantageously used in many types of formations. For example, in tar sands formations or relatively permeable formations containing heavy hydrocarbons, temperature limited heaters may be used to provide a controllable low temperature output for reducing the viscosity of fluids, mobilizing fluids, and/or enhancing the radial flow of fluids at or near the wellbore or in the formation. Temperature limited heaters may be used to inhibit excess coke formation due to overheating of the near wellbore region of the formation.
  • the use of temperature limited heaters eliminates or reduces the need for expensive temperature control circuitry.
  • the use of temperature limited heaters eliminates or reduces the need to perform temperature logging and/or the need to use fixed thermocouples on the heaters to monitor potential overheating at hot spots.
  • phase transformation for example, crystalline phase transformation or a change in the crystal structure
  • Ferromagnetic material used in the temperature limited heater may have a phase transformation (for example, a transformation from ferrite to austenite) that decreases the magnetic permeability of the ferromagnetic material.
  • This reduction in magnetic permeability is similar to reduction in magnetic permeability due to the magnetic transition of the ferromagnetic material at the Curie temperature.
  • the Curie temperature is the magnetic transition temperature of the ferrite phase of the ferromagnetic material.
  • the reduction in magnetic permeability results in a decrease in the AC or modulated DC resistance of the temperature limited heater near, at, or above the temperature of the phase transformation and/or the Curie temperature of the ferromagnetic material.
  • the phase transformation of the ferromagnetic material may occur over a temperature range.
  • the temperature range of the phase transformation depends on the ferromagnetic material and may vary, for example, over a range of about 5° C. to a range of about 200° C. Because the phase transformation takes place over a temperature range, the reduction in the magnetic permeability due to the phase transformation takes place over the temperature range. The reduction in magnetic permeability may also occur hysteretically over the temperature range of the phase transformation.
  • the phase transformation back to the lower temperature phase of the ferromagnetic material is slower than the phase transformation to the higher temperature phase (for example, the transition from austenite back to ferrite is slower than the transition from ferrite to austenite).
  • the slower phase transformation back to the lower temperature phase may cause hysteretic operation of the heater at or near the phase transformation temperature range that allows the heater to slowly increase to higher resistance after the resistance of the heater reduces due to high temperature.
  • the phase transformation temperature range overlaps with the reduction in the magnetic permeability when the temperature approaches the Curie temperature of the ferromagnetic material.
  • the overlap may produce a faster drop in electrical resistance versus temperature than if the reduction in magnetic permeability is solely due to the temperature approaching the Curie temperature.
  • the overlap may also produce hysteretic behavior of the temperature limited heater near the Curie temperature and/or in the phase transformation temperature range.
  • the hysteretic operation due to the phase transformation is a smoother transition than the reduction in magnetic permeability due to magnetic transition at the Curie temperature.
  • the smoother transition may be easier to control (for example, electrical control using a process control device that interacts with the power supply) than the sharper transition at the Curie temperature.
  • the Curie temperature is located inside the phase transformation range for selected metallurgies used in temperature limited heaters. This phenomenon provides temperature limited heaters with the smooth transition properties of the phase transformation in addition to a sharp and definite transition due to the reduction in magnetic properties at the Curie temperature. Such temperature limited heaters may be easy to control (due to the phase transformation) while providing finite temperature limits (due to the sharp Curie temperature transition). Using the phase transformation temperature range instead of and/or in addition to the Curie temperature in temperature limited heaters increases the number and range of metallurgies that may be used for temperature limited heaters.
  • alloy additions are made to the ferromagnetic material to adjust the temperature range of the phase transformation. For example, adding carbon to the ferromagnetic material may increase the phase transformation temperature range and lower the onset temperature of the phase transformation. Adding titanium to the ferromagnetic material may increase the onset temperature of the phase transformation and decrease the phase transformation temperature range. Alloy compositions may be adjusted to provide desired Curie temperature and phase transformation properties for the ferromagnetic material.
  • the alloy composition of the ferromagnetic material may be chosen based on desired properties for the ferromagnetic material (such as, but not limited to, magnetic permeability transition temperature or temperature range, resistance versus temperature profile, or power output). Addition of titanium may allow higher Curie temperatures to be obtained when adding cobalt to 410 stainless steel by raising the ferrite to austenite phase transformation temperature range to a temperature range that is above, or well above, the Curie temperature of the ferromagnetic material.
  • temperature limited heaters are more economical to manufacture or make than standard heaters.
  • Typical ferromagnetic materials include iron, carbon steel, or ferritic stainless steel. Such materials are inexpensive as compared to nickel-based heating alloys (such as nichrome, KanthalTM (Bulten-Kanthal AB, Sweden), and/or LOHMTM (Driver-Harris Company, Harrison, N.J., U.S.A.)) typically used in insulated conductor (mineral insulated cable) heaters.
  • the temperature limited heater is manufactured in continuous lengths as an insulated conductor heater to lower costs and improve reliability.
  • the temperature limited heater is placed in the heater well using a coiled tubing rig.
  • a heater that can be coiled on a spool may be manufactured by using metal such as ferritic stainless steel (for example, 409 stainless steel) that is welded using electrical resistance welding (ERW).
  • ERW electrical resistance welding
  • U.S. Pat. No. 7,032,809 to Hopkins which is incorporated by reference as if fully set forth herein, describes forming seam-welded pipe. To form a heater section, a metal strip from a roll is passed through a former where it is shaped into a tubular and then longitudinally welded using ERW.
  • a composite tubular may be formed from the seam-welded tubular.
  • the seam-welded tubular is passed through a second former where a conductive strip (for example, a copper strip) is applied, drawn down tightly on the tubular through a die, and longitudinally welded using ERW.
  • a sheath may be formed by longitudinally welding a support material (for example, steel such as 347H or 347HH) over the conductive strip material.
  • the support material may be a strip rolled over the conductive strip material.
  • An overburden section of the heater may be formed in a similar manner.
  • the overburden section uses a non-ferromagnetic material such as 304 stainless steel or 316 stainless steel instead of a ferromagnetic material.
  • the heater section and overburden section may be coupled using standard techniques such as butt welding using an orbital welder.
  • the overburden section material (the non-ferromagnetic material) may be pre-welded to the ferromagnetic material before rolling. The pre-welding may eliminate the need for a separate coupling step (for example, butt welding).
  • a flexible cable for example, a furnace cable such as a MGT 1000 furnace cable
  • An end bushing on the flexible cable may be welded to the tubular heater to provide an electrical current return path.
  • the tubular heater, including the flexible cable may be coiled onto a spool before installation into a heater well.
  • the temperature limited heater is installed using the coiled tubing rig.
  • the coiled tubing rig may place the temperature limited heater in a deformation resistant container in the formation.
  • the deformation resistant container may be placed in the heater well using conventional methods.
  • Temperature limited heaters may be used for heating hydrocarbon formations including, but not limited to, oil shale formations, coal formations, tar sands formations, and formations with heavy viscous oils. Temperature limited heaters may also be used in the field of environmental remediation to vaporize or destroy soil contaminants. Embodiments of temperature limited heaters may be used to heat fluids in a wellbore or sub-sea pipeline to inhibit deposition of paraffin or various hydrates. In some embodiments, a temperature limited heater is used for solution mining a subsurface formation (for example, an oil shale or a coal formation).
  • a fluid for example, molten salt
  • a temperature limited heater is attached to a sucker rod in the wellbore or is part of the sucker rod itself.
  • temperature limited heaters are used to heat a near wellbore region to reduce near wellbore oil viscosity during production of high viscosity crude oils and during transport of high viscosity oils to the surface.
  • a temperature limited heater enables gas lifting of a viscous oil by lowering the viscosity of the oil without coking the oil.
  • Temperature limited heaters may be used in sulfur transfer lines to maintain temperatures between about 110° C. and about 130° C.
  • the ferromagnetic alloy or ferromagnetic alloys used in the temperature limited heater determine the Curie temperature of the heater. Curie temperature data for various metals is listed in “American Institute of Physics Handbook,” Second Edition, McGraw-Hill, pages 5-170 through 5-176. Ferromagnetic conductors may include one or more of the ferromagnetic elements (iron, cobalt, and nickel) and/or alloys of these elements.
  • ferromagnetic conductors include iron-chromium (Fe—Cr) alloys that contain tungsten (W) (for example, HCM12A and SAVE12 (Sumitomo Metals Co., Japan)) and/or iron alloys that contain chromium (for example, Fe—Cr alloys, Fe—Cr—W alloys, Fe—Cr—V (vanadium) alloys, and Fe—Cr—Nb (Niobium) alloys).
  • W tungsten
  • SAVE12 Suditomo Metals Co., Japan
  • iron alloys that contain chromium
  • iron has a Curie temperature of approximately 770° C.
  • cobalt (Co) has a Curie temperature of approximately 1131° C.
  • nickel has a Curie temperature of approximately 358° C
  • An iron-cobalt alloy has a Curie temperature higher than the Curie temperature of iron.
  • iron-cobalt alloy with 2% by weight cobalt has a Curie temperature of approximately 800° C.
  • iron-cobalt alloy with 12% by weight cobalt has a Curie temperature of approximately 900° C.
  • iron-cobalt alloy with 20% by weight cobalt has a Curie temperature of approximately 950° C.
  • Iron-nickel alloy has a Curie temperature lower than the Curie temperature of iron.
  • iron-nickel alloy with 20% by weight nickel has a Curie temperature of approximately 720° C.
  • iron-nickel alloy with 60% by weight nickel has a Curie temperature of approximately 560° C.
  • Non-ferromagnetic elements used as alloys raise the Curie temperature of iron.
  • an iron-vanadium alloy with 5.9% by weight vanadium has a Curie temperature of approximately 815° C.
  • Other non-ferromagnetic elements for example, carbon, aluminum, copper, silicon, and/or chromium
  • Non-ferromagnetic materials that raise the Curie temperature may be combined with non-ferromagnetic materials that lower the Curie temperature and alloyed with iron or other ferromagnetic materials to produce a material with a desired Curie temperature and other desired physical and/or chemical properties.
  • the Curie temperature material is a ferrite such as NiFe 2 O 4 .
  • the Curie temperature material is a binary compound such as FeNi 3 or Fe 3 Al.
  • the improved alloy includes carbon, cobalt, iron, manganese, silicon, or mixtures thereof. In certain embodiments, the improved alloy includes, by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 0.1% to about 10% cobalt; about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, with the balance being iron.
  • the improved alloy includes chromium, carbon, cobalt, iron, manganese, silicon, titanium, vanadium, or mixtures thereof. In certain embodiments, the improved alloy includes, by weight: about 5% to about 20% cobalt, about 0.1% carbon, about 0.5% manganese, about 0.5% silicon, about 0.1% to about 2% vanadium with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 2% vanadium, above 0% to about 1% titanium, with the balance being iron.
  • the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2% vanadium, above 0% to about 1% titanium, with the balance being iron. In some embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 2% vanadium, with the balance being iron.
  • the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 15% cobalt, above 0% to about 1% titanium, with the balance being iron. In certain embodiments, the improved alloy includes, by weight: about 12% chromium, about 0.1% carbon, about 0.5% silicon, about 0.1% to about 0.5% manganese, above 0% to about 15% cobalt, with the balance being iron. The addition of vanadium may allow for use of higher amounts of cobalt in the improved alloy.
  • temperature limited heaters may include more than one ferromagnetic material. Such embodiments are within the scope of embodiments described herein if any conditions described herein apply to at least one of the ferromagnetic materials in the temperature limited heater.
  • Ferromagnetic properties generally decay as the Curie temperature and/or the phase transformation temperature range is approached.
  • the “Handbook of Electrical Heating for Industry” by C. James Erickson (IEEE Press, 1995) shows a typical curve for 1% carbon steel (steel with 1% carbon by weight).
  • the loss of magnetic permeability starts at temperatures above 650° C. and tends to be complete when temperatures exceed 730° C.
  • the self-limiting temperature may be somewhat below the actual Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the skin depth for current flow in 1% carbon steel is 0.132 cm at room temperature and increases to 0.445 cm at 720° C. From 720° C. to 730° C., the skin depth sharply increases to over 2.5 cm.
  • a temperature limited heater embodiment using 1% carbon steel begins to self-limit between 650° C. and 730° C.
  • Skin depth generally defines an effective penetration depth of time-varying current into the conductive material.
  • current density decreases exponentially with distance from an outer surface to the center along the radius of the conductor.
  • the depth at which the current density is approximately 1/e of the surface current density is called the skin depth.
  • ⁇ For a solid cylindrical rod with a diameter much greater than the penetration depth, or for hollow cylinders with a wall thickness exceeding the penetration depth, the skin depth, ⁇ , is:
  • Materials used in the temperature limited heater may be selected to provide a desired turndown ratio.
  • Turndown ratios of at least 1.1:1, 2:1, 3:1, 4:1, 5:1, 10:1, 30:1, or 50:1 may be selected for temperature limited heaters. Larger turndown ratios may also be used.
  • a selected turndown ratio may depend on a number of factors including, but not limited to, the type of formation in which the temperature limited heater is located (for example, a higher turndown ratio may be used for an oil shale formation with large variations in thermal conductivity between rich and lean oil shale layers) and/or a temperature limit of materials used in the wellbore (for example, temperature limits of heater materials).
  • the turndown ratio is increased by coupling additional copper or another good electrical conductor to the ferromagnetic material (for example, adding copper to lower the resistance above the Curie temperature and/or the phase transformation temperature range).
  • the temperature limited heater may provide a maximum heat output (power output) below the Curie temperature and/or the phase transformation temperature range of the heater.
  • the maximum heat output is at least 400 W/m (Watts per meter), 600 W/m, 700 W/m, 800 W/m, or higher up to 2000 W/m.
  • the temperature limited heater reduces the amount of heat output by a section of the heater when the temperature of the section of the heater approaches or is above the Curie temperature and/or the phase transformation temperature range.
  • the reduced amount of heat may be substantially less than the heat output below the Curie temperature and/or the phase transformation temperature range.
  • the reduced amount of heat is at most 400 W/m, 200 W/m, 100 W/m or may approach 0 W/m.
  • the temperature limited heater operates substantially independently of the thermal load on the heater in a certain operating temperature range.
  • “Thermal load” is the rate that heat is transferred from a heating system to its surroundings. It is to be understood that the thermal load may vary with temperature of the surroundings and/or the thermal conductivity of the surroundings.
  • the temperature limited heater operates at or above the Curie temperature and/or the phase transformation temperature range of the temperature limited heater such that the operating temperature of the heater increases at most by 3° C., 2° C., 1.5° C., 1° C., or 0.5° C. for a decrease in thermal load of 1 W/m proximate to a portion of the heater. In certain embodiments, the temperature limited heater operates in such a manner at a relatively constant current.
  • the AC or modulated DC resistance and/or the heat output of the temperature limited heater may decrease as the temperature approaches the Curie temperature and/or the phase transformation temperature range and decrease sharply near or above the Curie temperature due to the Curie effect and/or phase transformation effect.
  • the value of the electrical resistance or heat output above or near the Curie temperature and/or the phase transformation temperature range is at most one-half of the value of electrical resistance or heat output at a certain point below the Curie temperature and/or the phase transformation temperature range.
  • the heat output above or near the Curie temperature and/or the phase transformation temperature range is at most 90%, 70%, 50%, 30%, 20%, 10%, or less (down to 1%) of the heat output at a certain point below the Curie temperature and/or the phase transformation temperature range (for example, 30° C. below the Curie temperature, 40° C. below the Curie temperature, 50° C. below the Curie temperature, or 100° C. below the Curie temperature).
  • the electrical resistance above or near the Curie temperature and/or the phase transformation temperature range decreases to 80%, 70%, 60%, 50%, or less (down to 1%) of the electrical resistance at a certain point below the Curie temperature and/or the phase transformation temperature range (for example, 30° C. below the Curie temperature, 40° C. below the Curie temperature, 50° C. below the Curie temperature, or 100° C. below the Curie temperature).
  • AC frequency is adjusted to change the skin depth of the ferromagnetic material.
  • the skin depth of 1% carbon steel at room temperature is 0.132 cm at 60 Hz, 0.0762 cm at 180 Hz, and 0.046 cm at 440 Hz. Since heater diameter is typically larger than twice the skin depth, using a higher frequency (and thus a heater with a smaller diameter) reduces heater costs.
  • the higher frequency results in a higher turndown ratio.
  • the turndown ratio at a higher frequency is calculated by multiplying the turndown ratio at a lower frequency by the square root of the higher frequency divided by the lower frequency.
  • a frequency between 100 Hz and 1000 Hz, between 140 Hz and 200 Hz, or between 400 Hz and 600 Hz is used (for example, 180 Hz, 540 Hz, or 720 Hz).
  • high frequencies may be used. The frequencies may be greater than 1000 Hz.
  • the heater may be operated at a lower frequency when the heater is cold and operated at a higher frequency when the heater is hot.
  • Line frequency heating is generally favorable, however, because there is less need for expensive components such as power supplies, transformers, or current modulators that alter frequency.
  • Line frequency is the frequency of a general supply of current. Line frequency is typically 60 Hz, but may be 50 Hz or another frequency depending on the source for the supply of the current. Higher frequencies may be produced using commercially available equipment such as solid state variable frequency power supplies. Transformers that convert three-phase power to single-phase power with three times the frequency are commercially available.
  • high voltage three-phase power at 60 Hz may be transformed to single-phase power at 180 Hz and at a lower voltage.
  • Such transformers are less expensive and more energy efficient than solid state variable frequency power supplies.
  • transformers that convert three-phase power to single-phase power are used to increase the frequency of power supplied to the temperature limited heater.
  • modulated DC for example, chopped DC, waveform modulated DC, or cycled DC
  • a DC modulator or DC chopper may be coupled to a DC power supply to provide an output of modulated direct current.
  • the DC power supply may include means for modulating DC.
  • a DC modulator is a DC-to-DC converter system.
  • DC-to-DC converter systems are generally known in the art.
  • DC is typically modulated or chopped into a desired waveform. Waveforms for DC modulation include, but are not limited to, square-wave, sinusoidal, deformed sinusoidal, deformed square-wave, triangular, and other regular or irregular waveforms.
  • the modulated DC waveform generally defines the frequency of the modulated DC.
  • the modulated DC waveform may be selected to provide a desired modulated DC frequency.
  • the shape and/or the rate of modulation (such as the rate of chopping) of the modulated DC waveform may be varied to vary the modulated DC frequency.
  • DC may be modulated at frequencies that are higher than generally available AC frequencies.
  • modulated DC may be provided at frequencies of at least 1000 Hz. Increasing the frequency of supplied current to higher values advantageously increases the turndown ratio of the temperature limited heater.
  • the modulated DC waveform is adjusted or altered to vary the modulated DC frequency.
  • the DC modulator may be able to adjust or alter the modulated DC waveform at any time during use of the temperature limited heater and at high currents or voltages.
  • modulated DC provided to the temperature limited heater is not limited to a single frequency or even a small set of frequency values.
  • Waveform selection using the DC modulator typically allows for a wide range of modulated DC frequencies and for discrete control of the modulated DC frequency.
  • the modulated DC frequency is more easily set at a distinct value whereas AC frequency is generally limited to multiples of the line frequency.
  • Discrete control of the modulated DC frequency allows for more selective control over the turndown ratio of the temperature limited heater. Being able to selectively control the turndown ratio of the temperature limited heater allows for a broader range of materials to be used in designing and constructing the temperature limited heater.
  • the modulated DC frequency or the AC frequency is adjusted to compensate for changes in properties (for example, subsurface conditions such as temperature or pressure) of the temperature limited heater during use.
  • the modulated DC frequency or the AC frequency provided to the temperature limited heater is varied based on assessed downhole conditions. For example, as the temperature of the temperature limited heater in the wellbore increases, it may be advantageous to increase the frequency of the current provided to the heater, thus increasing the turndown ratio of the heater. In an embodiment, the downhole temperature of the temperature limited heater in the wellbore is assessed.
  • the modulated DC frequency, or the AC frequency is varied to adjust the turndown ratio of the temperature limited heater.
  • the turndown ratio may be adjusted to compensate for hot spots occurring along a length of the temperature limited heater. For example, the turndown ratio is increased because the temperature limited heater is getting too hot in certain locations.
  • the modulated DC frequency, or the AC frequency are varied to adjust a turndown ratio without assessing a subsurface condition.
  • an electrical current supply (for example, a supply of modulated DC or AC) provides a relatively constant amount of current that does not substantially vary with changes in load of the temperature limited heater.
  • the electrical current supply provides an amount of electrical current that remains within 15%, within 10%, within 5%, or within 2% of a selected constant current value when a load of the temperature limited heater changes.
  • Temperature limited heaters may generate an inductive load.
  • the inductive load is due to some applied electrical current being used by the ferromagnetic material to generate a magnetic field in addition to generating a resistive heat output.
  • the inductive load of the heater changes due to changes in the ferromagnetic properties of ferromagnetic materials in the heater with temperature.
  • the inductive load of the temperature limited heater may cause a phase shift between the current and the voltage applied to the heater.
  • a reduction in actual power applied to the temperature limited heater may be caused by a time lag in the current waveform (for example, the current has a phase shift relative to the voltage due to an inductive load) and/or by distortions in the current waveform (for example, distortions in the current waveform caused by introduced harmonics due to a non-linear load).
  • a time lag in the current waveform for example, the current has a phase shift relative to the voltage due to an inductive load
  • distortions in the current waveform for example, distortions in the current waveform caused by introduced harmonics due to a non-linear load.
  • the ratio of actual power applied and the apparent power that would have been transmitted if the same current were in phase and undistorted is the power factor.
  • the power factor is always less than or equal to 1.
  • the power factor is 1 when there is no phase shift or distortion in the waveform.
  • P is the actual power applied to a heater
  • I is the applied current
  • V is the applied voltage
  • ⁇ is the phase angle difference between voltage and current.
  • Other phenomena such as waveform distortion may contribute to further lowering of the power factor. If there is no distortion in the waveform, then cos( ⁇ ) is equal to the power factor.
  • the temperature limited heater includes an inner conductor inside an outer conductor.
  • the inner conductor and the outer conductor are radially disposed about a central axis.
  • the inner and outer conductors may be separated by an insulation layer.
  • the inner and outer conductors are coupled at the bottom of the temperature limited heater. Electrical current may flow into the temperature limited heater through the inner conductor and return through the outer conductor.
  • One or both conductors may include ferromagnetic material.
  • the insulation layer may include an electrically insulating ceramic with high thermal conductivity, such as magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof.
  • the insulating layer may be a compacted powder (for example, compacted ceramic powder). Compaction may improve thermal conductivity and provide better insulation resistance.
  • polymer insulation made from, for example, fluoropolymers, polyimides, polyamides, and/or polyethylenes, may be used. In some embodiments, the polymer insulation is made of perfluoroalkoxy (PFA) or polyetheretherketone (PEEKTM (Victrex Ltd, England)).
  • the insulating layer may be chosen to be substantially infrared transparent to aid heat transfer from the inner conductor to the outer conductor.
  • the insulating layer is transparent quartz sand.
  • the insulation layer may be air or a non-reactive gas such as helium, nitrogen, or sulfur hexafluoride. If the insulation layer is air or a non-reactive gas, there may be insulating spacers designed to inhibit electrical contact between the inner conductor and the outer conductor.
  • the insulating spacers may be made of, for example, high purity aluminum oxide or another thermally conducting, electrically insulating material such as silicon nitride.
  • the insulating spacers may be a fibrous ceramic material such as NextelTM 312 (3M Corporation, St.
  • Ceramic material may be made of alumina, alumina-silicate, alumina-borosilicate, silicon nitride, boron nitride, or other materials.
  • the insulation layer may be flexible and/or substantially deformation tolerant.
  • the temperature limited heater may be flexible and/or substantially deformation tolerant. Forces on the outer conductor can be transmitted through the insulation layer to the solid inner conductor, which may resist crushing. Such a temperature limited heater may be bent, dog-legged, and spiraled without causing the outer conductor and the inner conductor to electrically short to each other. Deformation tolerance may be important if the wellbore is likely to undergo substantial deformation during heating of the formation.
  • an outermost layer of the temperature limited heater (for example, the outer conductor) is chosen for corrosion resistance, yield strength, and/or creep resistance.
  • austenitic (non-ferromagnetic) stainless steels such as 201, 304H, 347H, 347HH, 316H, 310H, 347HP, NF709 (Nippon Steel Corp., Japan) stainless steels, or combinations thereof may be used in the outer conductor.
  • the outermost layer may also include a clad conductor.
  • a corrosion resistant alloy such as 800H or 347H stainless steel may be clad for corrosion protection over a ferromagnetic carbon steel tubular.
  • the outermost layer may be constructed from ferromagnetic metal with good corrosion resistance such as one of the ferritic stainless steels.
  • ferromagnetic metal with good corrosion resistance
  • a ferritic alloy of 82.3% by weight iron with 17.7% by weight chromium (Curie temperature of 678° C.) provides desired corrosion resistance.
  • the Metals Handbook, vol. 8, page 291 includes a graph of Curie temperature of iron-chromium alloys versus the amount of chromium in the alloys.
  • a separate support rod or tubular (made from 347H stainless steel) is coupled to the temperature limited heater made from an iron-chromium alloy to provide yield strength and/or creep resistance.
  • the support material and/or the ferromagnetic material is selected to provide a 100,000 hour creep-rupture strength of at least 20.7 MPa at 650° C. In some embodiments, the 100,000 hour creep-rupture strength is at least 13.8 MPa at 650° C. or at least 6.9 MPa at 650° C.
  • 347H steel has a favorable creep-rupture strength at or above 650° C.
  • the 100,000 hour creep-rupture strength ranges from 6.9 MPa to 41.3 MPa or more for longer heaters and/or higher earth or fluid stresses.
  • the skin effect current path occurs on the outside of the inner conductor and on the inside of the outer conductor.
  • the outside of the outer conductor may be clad with the corrosion resistant alloy, such as stainless steel, without affecting the skin effect current path on the inside of the outer conductor.
  • a ferromagnetic conductor with a thickness of at least the skin depth at the Curie temperature and/or the phase transformation temperature range allows a substantial decrease in resistance of the ferromagnetic material as the skin depth increases sharply near the Curie temperature and/or the phase transformation temperature range.
  • the thickness of the conductor may be 1.5 times the skin depth near the Curie temperature and/or the phase transformation temperature range, 3 times the skin depth near the Curie temperature and/or the phase transformation temperature range, or even 10 or more times the skin depth near the Curie temperature and/or the phase transformation temperature range.
  • thickness of the ferromagnetic conductor may be substantially the same as the skin depth near the Curie temperature and/or the phase transformation temperature range.
  • the ferromagnetic conductor clad with copper has a thickness of at least three-fourths of the skin depth near the Curie temperature and/or the phase transformation temperature range.
  • the temperature limited heater includes a composite conductor with a ferromagnetic tubular and a non-ferromagnetic, high electrical conductivity core.
  • the non-ferromagnetic, high electrical conductivity core reduces a required diameter of the conductor.
  • the conductor may be composite 1.19 cm diameter conductor with a core of 0.575 cm diameter copper clad with a 0.298 cm thickness of ferritic stainless steel or carbon steel surrounding the core.
  • the core or non-ferromagnetic conductor may be copper or copper alloy.
  • the core or non-ferromagnetic conductor may also be made of other metals that exhibit low electrical resistivity and relative magnetic permeabilities near 1 (for example, substantially non-ferromagnetic materials such as aluminum and aluminum alloys, phosphor bronze, beryllium copper, and/or brass).
  • a composite conductor allows the electrical resistance of the temperature limited heater to decrease more steeply near the Curie temperature and/or the phase transformation temperature range. As the skin depth increases near the Curie temperature and/or the phase transformation temperature range to include the copper core, the electrical resistance decreases very sharply.
  • the composite conductor may increase the conductivity of the temperature limited heater and/or allow the heater to operate at lower voltages.
  • the composite conductor exhibits a relatively flat resistance versus temperature profile at temperatures below a region near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor of the composite conductor.
  • the temperature limited heater exhibits a relatively flat resistance versus temperature profile between 100° C. and 750° C. or between 300° C. and 600° C.
  • the relatively flat resistance versus temperature profile may also be exhibited in other temperature ranges by adjusting, for example, materials and/or the configuration of materials in the temperature limited heater.
  • the relative thickness of each material in the composite conductor is selected to produce a desired resistivity versus temperature profile for the temperature limited heater.
  • the relative thickness of each material in a composite conductor is selected to produce a desired resistivity versus temperature profile for a temperature limited heater.
  • the composite conductor is an inner conductor surrounded by 0.127 cm thick magnesium oxide powder as an insulator.
  • the outer conductor may be 304H stainless steel with a wall thickness of 0.127 cm.
  • the outside diameter of the heater may be about 1.65 cm.
  • a composite conductor for example, a composite inner conductor or a composite outer conductor
  • coextrusion for example, roll forming, tight fit tubing
  • tight fit tubing for example, cooling the inner
  • a ferromagnetic conductor is braided over a non-ferromagnetic conductor.
  • composite conductors are formed using methods similar to those used for cladding (for example, cladding copper to steel). A metallurgical bond between copper cladding and base ferromagnetic material may be advantageous.
  • Composite conductors produced by a coextrusion process that forms a good metallurgical bond may be provided by Anomet Products, Inc. (Shrewsbury, Mass., U.S.A.).
  • longitudinal strip welding it may be difficult to use longitudinal strip welding techniques if the desired thickness of a layer of a first material has such a large thickness, in relation to the inner core/layer onto which such layer is to be bended, that it does not effectively and/or efficiently bend around an inner core or layer that is made of a second material.
  • a first layer of the first material may be bent around an inner core or layer of second material, and then a second layer of the first material may be bent around the first layer of the first material, with the thicknesses of the first and second layers being such that the first and second layers will readily bend around the inner core or layer in a longitudinal strip welding process.
  • the two layers of the first material may together form the total desired thickness of the first material.
  • FIGS. 15-32 depict various embodiments of temperature limited heaters.
  • One or more features of an embodiment of the temperature limited heater depicted in any of these figures may be combined with one or more features of other embodiments of temperature limited heaters depicted in these figures.
  • temperature limited heaters are dimensioned to operate at a frequency of 60 Hz AC. It is to be understood that dimensions of the temperature limited heater may be adjusted from those described herein to operate in a similar manner at other AC frequencies or with modulated DC current.
  • the temperature limited heaters may be used in conductor-in-conduit heaters.
  • the majority of the resistive heat is generated in the conductor, and the heat radiatively, conductively and/or convectively transfers to the conduit.
  • the majority of the resistive heat is generated in the conduit.
  • FIG. 15 depicts a cross-sectional representation of an embodiment of the temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section.
  • FIGS. 16 and 17 depict transverse cross-sectional views of the embodiment shown in FIG. 15 .
  • ferromagnetic section 358 is used to provide heat to hydrocarbon layers in the formation.
  • Non-ferromagnetic section 360 is used in the overburden of the formation.
  • Non-ferromagnetic section 360 provides little or no heat to the overburden, thus inhibiting heat losses in the overburden and improving heater efficiency.
  • Ferromagnetic section 358 includes a ferromagnetic material such as 409 stainless steel or 410 stainless steel. Ferromagnetic section 358 has a thickness of 0.3 cm.
  • Non-ferromagnetic section 360 is copper with a thickness of 0.3 cm.
  • Inner conductor 362 is copper.
  • Inner conductor 362 has a diameter of 0.9 cm.
  • Electrical insulator 364 is silicon nitride, boron nitride, magnesium oxide powder, or another suitable insulator material. Electrical insulator 364 has a thickness of 0.1 cm to 0.3 cm.
  • FIG. 18 depicts a cross-sectional representation of an embodiment of a temperature limited heater with an outer conductor having a ferromagnetic section and a non-ferromagnetic section placed inside a sheath.
  • FIGS. 19 , 20 , and 21 depict transverse cross-sectional views of the embodiment shown in FIG. 18 .
  • Ferromagnetic section 358 is 410 stainless steel with a thickness of 0.6 cm.
  • Non-ferromagnetic section 360 is copper with a thickness of 0.6 cm.
  • Inner conductor 362 is copper with a diameter of 0.9 cm.
  • Outer conductor 366 includes ferromagnetic material. Outer conductor 366 provides some heat in the overburden section of the heater.
  • Outer conductor 366 is 409, 410, or 446 stainless steel with an outer diameter of 3.0 cm and a thickness of 0.6 cm.
  • Electrical insulator 364 includes compacted magnesium oxide powder with a thickness of 0.3 cm. In some embodiments, electrical insulator 364 includes silicon nitride, boron nitride, or hexagonal type boron nitride.
  • Conductive section 368 may couple inner conductor 362 with ferromagnetic section 358 and/or outer conductor 366 .
  • FIG. 22A and FIG. 22B depict cross-sectional representations of an embodiment of a temperature limited heater with a ferromagnetic outer conductor.
  • the outer conductor is clad with a conductive layer and a corrosion resistant alloy.
  • Inner conductor 362 is copper.
  • Electrical insulator 364 is silicon nitride, boron nitride, or magnesium oxide.
  • Outer conductor 366 is a 1′′ Schedule 80 446 stainless steel pipe. Outer conductor 366 is coupled to jacket 370 .
  • Jacket 370 is made from corrosion resistant material such as 347H stainless steel.
  • conductive layer 372 is placed between outer conductor 366 and jacket 370 .
  • Conductive layer 372 is a copper layer.
  • Heat is produced primarily in outer conductor 366 , resulting in a small temperature differential across electrical insulator 364 .
  • Conductive layer 372 allows a sharp decrease in the resistance of outer conductor 366 as the outer conductor approaches the Curie temperature and/or the phase transformation temperature range.
  • Jacket 370 provides protection from corrosive fluids in the wellbore.
  • inner conductor 362 includes a core of copper or another non-ferromagnetic conductor surrounded by ferromagnetic material (for example, a low Curie temperature material such as Invar 36).
  • the copper core has an outer diameter between about 0.125′′ and about 0.375′′ (for example, about 0.5′′) and the ferromagnetic material has an outer diameter between about 0.625′′ and about 1′′ (for example, about 0.75′′).
  • the copper core may increase the turndown ratio of the heater and/or reduce the thickness needed in the ferromagnetic material, which may allow a lower cost heater to be made.
  • Electrical insulator 364 may be magnesium oxide with an outer diameter between about 1′′ and about 1.2′′ (for example, about 1.11′′).
  • Outer conductor 366 may include non-ferromagnetic electrically conductive material with high mechanical strength such as 825 stainless steel. Outer conductor 366 may have an outer diameter between about 1.2′′ and about 1.5′′ (for example, about 1.33′′). In certain embodiments, inner conductor 362 is a forward current path and outer conductor 366 is a return current path.
  • Conductive layer 372 may include copper or another non-ferromagnetic material with an outer diameter between about 1.3′′ and about 1.4′′ (for example, about 1.384′′). Conductive layer 372 may decrease the resistance of the return current path (to reduce the heat output of the return path such that little or no heat is generated in the return path) and/or increase the turndown ratio of the heater.
  • Conductive layer 372 may reduce the thickness needed in outer conductor 366 and/or jacket 370 , which may allow a lower cost heater to be made.
  • Jacket 370 may include ferromagnetic material such as carbon steel or 410 stainless steel with an outer diameter between about 1.6′′ and about 1.8′′ (for example, about 1.684′′).
  • Jacket 370 may have a thickness of at least 2 times the skin depth of the ferromagnetic material in the jacket.
  • Jacket 370 may provide protection from corrosive fluids in the wellbore.
  • inner conductor 362 , electrical insulator 364 , and outer conductor 366 are formed as composite heater (for example, an insulated conductor heater) and conductive layer 372 and jacket 370 are formed around (for example, wrapped) the composite heater and welded together to form the larger heater embodiment described herein.
  • jacket 370 includes ferromagnetic material that has a higher Curie temperature than ferromagnetic material in inner conductor 362 .
  • a temperature limited heater may “contain” current such that the current does not easily flow from the heater to the surrounding formation and/or to any surrounding fluids (for example, production fluids, formation fluids, brine, groundwater, or formation water).
  • a majority of the current flows through inner conductor 362 until the Curie temperature of the ferromagnetic material in the inner conductor is reached. After the Curie temperature of ferromagnetic material in inner conductor 362 is reached, a majority of the current flows through the core of copper in the inner conductor.
  • the ferromagnetic properties of jacket 370 inhibit the current from flowing outside the jacket and “contain” the current.
  • Such a heater may be used in lower temperature applications where fluids are present such as providing heat in a production wellbore to increase oil production.
  • the conductor (for example, an inner conductor, an outer conductor, or a ferromagnetic conductor) is the composite conductor that includes two or more different materials.
  • the composite conductor includes two or more ferromagnetic materials.
  • the composite ferromagnetic conductor includes two or more radially disposed materials.
  • the composite conductor includes a ferromagnetic conductor and a non-ferromagnetic conductor.
  • the composite conductor includes the ferromagnetic conductor placed over a non-ferromagnetic core.
  • Two or more materials may be used to obtain a relatively flat electrical resistivity versus temperature profile in a temperature region below the Curie temperature, and/or the phase transformation temperature range, and/or a sharp decrease (a high turndown ratio) in the electrical resistivity at or near the Curie temperature and/or the phase transformation temperature range.
  • two or more materials are used to provide more than one Curie temperature and/or phase transformation temperature range for the temperature limited heater.
  • the composite electrical conductor may be used as the conductor in any electrical heater embodiment described herein.
  • the composite conductor may be used as the conductor in a conductor-in-conduit heater or an insulated conductor heater.
  • the composite conductor may be coupled to a support member such as a support conductor.
  • the support member may be used to provide support to the composite conductor so that the composite conductor is not relied upon for strength at or near the Curie temperature and/or the phase transformation temperature range.
  • the support member may be useful for heaters of lengths of at least 100 m.
  • the support member may be a non-ferromagnetic member that has good high temperature creep strength.
  • materials that are used for a support member include, but are not limited to, Haynes® 625 alloy and Haynes® HR120® alloy (Haynes International, Kokomo, Ind., U.S.A.), NF709, Incoloy® 800H alloy and 347HP alloy (Allegheny Ludlum Corp., Pittsburgh, Pa., U.S.A.).
  • materials in a composite conductor are directly coupled (for example, brazed, metallurgically bonded, or swaged) to each other and/or the support member.
  • Using a support member may reduce the need for the ferromagnetic member to provide support for the temperature limited heater, especially at or near the Curie temperature and/or the phase transformation temperature range.
  • the temperature limited heater may be designed with more flexibility in the selection of ferromagnetic materials.
  • FIG. 23 depicts a cross-sectional representation of an embodiment of the composite conductor with the support member.
  • Core 374 is surrounded by ferromagnetic conductor 376 and support member 378 .
  • core 374 , ferromagnetic conductor 376 , and support member 378 are directly coupled (for example, brazed together or metallurgically bonded together).
  • core 374 is copper
  • ferromagnetic conductor 376 is 446 stainless steel
  • support member 378 is 347H alloy.
  • support member 378 is a Schedule 80 pipe. Support member 378 surrounds the composite conductor having ferromagnetic conductor 376 and core 374 .
  • Ferromagnetic conductor 376 and core 374 may be joined to form the composite conductor by, for example, a coextrusion process.
  • the composite conductor is a 1.9 cm outside diameter 446 stainless steel ferromagnetic conductor surrounding a 0.95 cm diameter copper core.
  • the diameter of core 374 is adjusted relative to a constant outside diameter of ferromagnetic conductor 376 to adjust the turndown ratio of the temperature limited heater.
  • the diameter of core 374 may be increased to 1.14 cm while maintaining the outside diameter of ferromagnetic conductor 376 at 1.9 cm to increase the turndown ratio of the heater.
  • FIG. 24 depicts a cross-sectional representation of an embodiment of the composite conductor with support member 378 separating the conductors.
  • core 374 is copper with a diameter of 0.95 cm
  • support member 378 is 347H alloy with an outside diameter of 1.9 cm
  • ferromagnetic conductor 376 is 446 stainless steel with an outside diameter of 2.7 cm.
  • the support member depicted in FIG. 24 has a lower creep strength relative to the support members depicted in FIG. 23 .
  • support member 378 is located inside the composite conductor.
  • FIG. 25 depicts a cross-sectional representation of an embodiment of the composite conductor surrounding support member 378 .
  • Support member 378 is made of 347H alloy.
  • Inner conductor 362 is copper.
  • Ferromagnetic conductor 376 is 446 stainless steel.
  • support member 378 is 1.25 cm diameter 347H alloy, inner conductor 362 is 1.9 cm outside diameter copper, and ferromagnetic conductor 376 is 2.7 cm outside diameter 446 stainless steel.
  • the turndown ratio is higher than the turndown ratio for the embodiments depicted in FIGS. 23 , 24 , and 26 for the same outside diameter, but the creep strength is lower.
  • the thickness of inner conductor 362 which is copper, is reduced and the thickness of support member 378 is increased to increase the creep strength at the expense of reduced turndown ratio.
  • the diameter of support member 378 is increased to 1.6 cm while maintaining the outside diameter of inner conductor 362 at 1.9 cm to reduce the thickness of the conduit. This reduction in thickness of inner conductor 362 results in a decreased turndown ratio relative to the thicker inner conductor embodiment but an increased creep strength.
  • FIG. 26 depicts a cross-sectional representation of an embodiment of the composite conductor surrounding support member 378 .
  • support member 378 is 347H alloy with a 0.63 cm diameter center hole.
  • support member 378 is a preformed conduit.
  • support member 378 is formed by having a dissolvable material (for example, copper dissolvable by nitric acid) located inside the support member during formation of the composite conductor. The dissolvable material is dissolved to form the hole after the conductor is assembled.
  • a dissolvable material for example, copper dissolvable by nitric acid
  • support member 378 is 347H alloy with an inside diameter of 0.63 cm and an outside diameter of 1.6 cm
  • inner conductor 362 is copper with an outside diameter of 1.8 cm
  • ferromagnetic conductor 376 is 446 stainless steel with an outside diameter of 2.7 cm.
  • the composite electrical conductor is used as the conductor in the conductor-in-conduit heater.
  • the composite electrical conductor may be used as conductor 380 in FIG. 27 .
  • FIG. 27 depicts a cross-sectional representation of an embodiment of the conductor-in-conduit heater.
  • Conductor 380 is disposed in conduit 382 .
  • Conductor 380 is a rod or conduit of electrically conductive material.
  • Low resistance sections 384 are present at both ends of conductor 380 to generate less heating in these sections.
  • Low resistance section 384 is formed by having a greater cross-sectional area of conductor 380 in that section, or the sections are made of material having less resistance.
  • low resistance section 384 includes a low resistance conductor coupled to conductor 380 .
  • Conduit 382 is made of an electrically conductive material. Conduit 382 is disposed in opening 386 in hydrocarbon layer 388 . Opening 386 has a diameter that accommodates conduit 382 .
  • Conductor 380 may be centered in conduit 382 by centralizers 390 .
  • Centralizers 390 electrically isolate conductor 380 from conduit 382 .
  • Centralizers 390 inhibit movement and properly locate conductor 380 in conduit 382 .
  • Centralizers 390 are made of ceramic material or a combination of ceramic and metallic materials.
  • Centralizers 390 inhibit deformation of conductor 380 in conduit 382 .
  • Centralizers 390 are touching or spaced at intervals between approximately 0.1 m (meters) and approximately 3 m or more along conductor 380 .
  • a second low resistance section 384 of conductor 380 may couple conductor 380 to wellhead 392 .
  • Electrical current may be applied to conductor 380 from power cable 394 through low resistance section 384 of conductor 380 .
  • Electrical current passes from conductor 380 through sliding connector 396 to conduit 382 .
  • Conduit 382 may be electrically insulated from overburden casing 398 and from wellhead 392 to return electrical current to power cable 394 .
  • Heat may be generated in conductor 380 and conduit 382 . The generated heat may radiate in conduit 382 and opening 386 to heat at least a portion of hydrocarbon layer 388 .
  • Overburden casing 398 may be disposed in overburden 400 .
  • overburden casing 398 is surrounded by materials (for example, reinforcing material and/or cement) that inhibit heating of overburden 400 .
  • Low resistance section 384 of conductor 380 may be placed in overburden casing 398 .
  • Low resistance section 384 of conductor 380 is made of, for example, carbon steel.
  • Low resistance section 384 of conductor 380 may be centralized in overburden casing 398 using centralizers 390 .
  • Centralizers 390 are spaced at intervals of approximately 6 m to approximately 12 m or, for example, approximately 9 m along low resistance section 384 of conductor 380 .
  • low resistance sections 384 are coupled to conductor 380 by one or more welds. In other heater embodiments, low resistance sections are threaded, threaded and welded, or otherwise coupled to the conductor. Low resistance section 384 generates little or no heat in overburden casing 398 .
  • Packing 402 may be placed between overburden casing 398 and opening 386 . Packing 402 may be used as a cap at the junction of overburden 400 and hydrocarbon layer 388 to allow filling of materials in the annulus between overburden casing 398 and opening 386 . In some embodiments, packing 402 inhibits fluid from flowing from opening 386 to surface 404 .
  • FIG. 28 depicts a cross-sectional representation of an embodiment of a removable conductor-in-conduit heat source.
  • Conduit 382 may be placed in opening 386 through overburden 400 such that a gap remains between the conduit and overburden casing 398 . Fluids may be removed from opening 386 through the gap between conduit 382 and overburden casing 398 . Fluids may be removed from the gap through conduit 406 .
  • Conduit 382 and components of the heat source included in the conduit that are coupled to wellhead 392 may be removed from opening 386 as a single unit. The heat source may be removed as a single unit to be repaired, replaced, and/or used in another portion of the formation.
  • a majority of the current flows through material with highly non-linear functions of magnetic field (H) versus magnetic induction (B).
  • H magnetic field
  • B magnetic induction
  • These non-linear functions may cause strong inductive effects and distortion that lead to decreased power factor in the temperature limited heater at temperatures below the Curie temperature and/or the phase transformation temperature range.
  • These effects may render the electrical power supply to the temperature limited heater difficult to control and may result in additional current flow through surface and/or overburden power supply conductors.
  • Expensive and/or difficult to implement control systems such as variable capacitors or modulated power supplies may be used to compensate for these effects and to control temperature limited heaters where the majority of the resistive heat output is provided by current flow through the ferromagnetic material.
  • the ferromagnetic conductor confines a majority of the flow of electrical current to an electrical conductor coupled to the ferromagnetic conductor when the temperature limited heater is below or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the electrical conductor may be a sheath, jacket, support member, corrosion resistant member, or other electrically resistive member.
  • the ferromagnetic conductor confines a majority of the flow of electrical current to the electrical conductor positioned between an outermost layer and the ferromagnetic conductor.
  • the ferromagnetic conductor is located in the cross section of the temperature limited heater such that the magnetic properties of the ferromagnetic conductor at or below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor confine the majority of the flow of electrical current to the electrical conductor.
  • the majority of the flow of electrical current is confined to the electrical conductor due to the skin effect of the ferromagnetic conductor.
  • the majority of the current is flowing through material with substantially linear resistive properties throughout most of the operating range of the heater.
  • the ferromagnetic conductor and the electrical conductor are located in the cross section of the temperature limited heater so that the skin effect of the ferromagnetic material limits the penetration depth of electrical current in the electrical conductor and the ferromagnetic conductor at temperatures below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the electrical conductor provides a majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the dimensions of the electrical conductor may be chosen to provide desired heat output characteristics.
  • the temperature limited heater has a resistance versus temperature profile that at least partially reflects the resistance versus temperature profile of the material in the electrical conductor.
  • the resistance versus temperature profile of the temperature limited heater is substantially linear below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor if the material in the electrical conductor has a substantially linear resistance versus temperature profile.
  • the resistance of the temperature limited heater has little or no dependence on the current flowing through the heater until the temperature nears the Curie temperature and/or the phase transformation temperature range. The majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range.
  • Resistance versus temperature profiles for temperature limited heaters in which the majority of the current flows in the electrical conductor also tend to exhibit sharper reductions in resistance near or at the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the sharper reductions in resistance near or at the Curie temperature and/or the phase transformation temperature range are easier to control than more gradual resistance reductions near the Curie temperature and/or the phase transformation temperature range because little current is flowing through the ferromagnetic material.
  • the material and/or the dimensions of the material in the electrical conductor are selected so that the temperature limited heater has a desired resistance versus temperature profile below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • Temperature limited heaters in which the majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range are easier to predict and/or control.
  • Behavior of temperature limited heaters in which the majority of the current flows in the electrical conductor rather than the ferromagnetic conductor below the Curie temperature and/or the phase transformation temperature range may be predicted by, for example, the resistance versus temperature profile and/or the power factor versus temperature profile.
  • Resistance versus temperature profiles and/or power factor versus temperature profiles may be assessed or predicted by, for example, experimental measurements that assess the behavior of the temperature limited heater, analytical equations that assess or predict the behavior of the temperature limited heater, and/or simulations that assess or predict the behavior of the temperature limited heater.
  • assessed or predicted behavior of the temperature limited heater is used to control the temperature limited heater.
  • the temperature limited heater may be controlled based on measurements (assessments) of the resistance and/or the power factor during operation of the heater.
  • the power, or current, supplied to the temperature limited heater is controlled based on assessment of the resistance and/or the power factor of the heater during operation of the heater and the comparison of this assessment versus the predicted behavior of the heater.
  • the temperature limited heater is controlled without measurement of the temperature of the heater or a temperature near the heater. Controlling the temperature limited heater without temperature measurement eliminates operating costs associated with downhole temperature measurement. Controlling the temperature limited heater based on assessment of the resistance and/or the power factor of the heater also reduces the time for making adjustments in the power or current supplied to the heater compared to controlling the heater based on measured temperature.
  • a highly electrically conductive member is coupled to the ferromagnetic conductor and the electrical conductor to reduce the electrical resistance of the temperature limited heater at or above the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the highly electrically conductive member may be an inner conductor, a core, or another conductive member of copper, aluminum, nickel, or alloys thereof.
  • the ferromagnetic conductor that confines the majority of the flow of electrical current to the electrical conductor at temperatures below the Curie temperature and/or the phase transformation temperature range may have a relatively small cross section compared to the ferromagnetic conductor in temperature limited heaters that use the ferromagnetic conductor to provide the majority of resistive heat output up to or near the Curie temperature and/or the phase transformation temperature range.
  • a temperature limited heater that uses the electrical conductor to provide a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range has low magnetic inductance at temperatures below the Curie temperature and/or the phase transformation temperature range because less current is flowing through the ferromagnetic conductor as compared to the temperature limited heater where the majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range is provided by the ferromagnetic material.
  • Magnetic field (H) at radius (r) of the ferromagnetic conductor is proportional to the current (I) flowing through the ferromagnetic conductor and the core divided by the radius, or:
  • the magnetic field of the temperature limited heater may be significantly smaller than the magnetic field of the temperature limited heater where the majority of the current flows through the ferromagnetic material.
  • the relative magnetic permeability ( ⁇ ) may be large for small magnetic fields.
  • the skin depth ( ⁇ ) of the ferromagnetic conductor is inversely proportional to the square root of the relative magnetic permeability ( ⁇ ):
  • the radius (or thickness) of the ferromagnetic conductor may be decreased for ferromagnetic materials with large relative magnetic permeabilities to compensate for the decreased skin depth while still allowing the skin effect to limit the penetration depth of the electrical current to the electrical conductor at temperatures below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • the radius (thickness) of the ferromagnetic conductor may be between 0.3 mm and 8 mm, between 0.3 mm and 2 mm, or between 2 mm and 4 mm depending on the relative magnetic permeability of the ferromagnetic conductor. Decreasing the thickness of the ferromagnetic conductor decreases costs of manufacturing the temperature limited heater, as the cost of ferromagnetic material tends to be a significant portion of the cost of the temperature limited heater. Increasing the relative magnetic permeability of the ferromagnetic conductor provides a higher turndown ratio and a sharper decrease in electrical resistance for the temperature limited heater at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • Ferromagnetic materials such as purified iron or iron-cobalt alloys
  • high relative magnetic permeabilities for example, at least 200, at least 1000, at least 1 ⁇ 10 4 , or at least 1 ⁇ 10 5
  • high Curie temperatures for example, at least 600° C., at least 700° C., or at least 800° C.
  • the electrical conductor may provide corrosion resistance and/or high mechanical strength at high temperatures for the temperature limited heater.
  • the ferromagnetic conductor may be chosen primarily for its ferromagnetic properties.
  • the effect on the power factor is reduced compared to temperature limited heaters in which the ferromagnetic conductor provides a majority of the resistive heat output below the Curie temperature and/or the phase transformation temperature range.
  • external compensation for example, variable capacitors or waveform modification
  • the temperature limited heater which confines the majority of the flow of electrical current to the electrical conductor below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor, maintains the power factor above 0.85, above 0.9, or above 0.95 during use of the heater. Any reduction in the power factor occurs only in sections of the temperature limited heater at temperatures near the Curie temperature and/or the phase transformation temperature range. Most sections of the temperature limited heater are typically not at or near the Curie temperature and/or the phase transformation temperature range during use. These sections have a high power factor that approaches 1.0. The power factor for the entire temperature limited heater is maintained above 0.85, above 0.9, or above 0.95 during use of the heater even if some sections of the heater have power factors below 0.85.
  • Maintaining high power factors allows for less expensive power supplies and/or control devices such as solid state power supplies or SCRs (silicon controlled rectifiers). These devices may fail to operate properly if the power factor varies by too large an amount because of inductive loads. With the power factors maintained at high values; however, these devices may be used to provide power to the temperature limited heater. Solid state power supplies have the advantage of allowing fine tuning and controlled adjustment of the power supplied to the temperature limited heater.
  • transformers are used to provide power to the temperature limited heater. Multiple voltage taps may be made into the transformer to provide power to the temperature limited heater. Multiple voltage taps allow the current supplied to switch back and forth between the multiple voltages. This maintains the current within a range bound by the multiple voltage taps.
  • the highly electrically conductive member, or inner conductor increases the turndown ratio of the temperature limited heater.
  • thickness of the highly electrically conductive member is increased to increase the turndown ratio of the temperature limited heater.
  • the thickness of the electrical conductor is reduced to increase the turndown ratio of the temperature limited heater.
  • the turndown ratio of the temperature limited heater is between 1.1 and 10, between 2 and 8, or between 3 and 6 (for example, the turndown ratio is at least 1.1, at least 2, or at least 3).
  • FIG. 29 depicts an embodiment of a temperature limited heater in which the support member provides a majority of the heat output below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • Core 374 is an inner conductor of the temperature limited heater.
  • core 374 is a highly electrically conductive material such as copper or aluminum.
  • core 374 is a copper alloy that provides mechanical strength and good electrically conductivity such as a dispersion strengthened copper.
  • core 374 is Glidcop® (SCM Metal Products, Inc., Research Triangle Park, North Carolina, U.S.A.).
  • Ferromagnetic conductor 376 is a thin layer of ferromagnetic material between electrical conductor 408 and core 374 .
  • electrical conductor 408 is also support member 378 .
  • ferromagnetic conductor 376 is iron or an iron alloy.
  • ferromagnetic conductor 376 includes ferromagnetic material with a high relative magnetic permeability.
  • ferromagnetic conductor 376 may be purified iron such as Armco ingot iron (AK Steel Ltd., United Kingdom). Iron with some impurities typically has a relative magnetic permeability on the order of 400 . Purifying the iron by annealing the iron in hydrogen gas (H 2 ) at 1450° C. increases the relative magnetic permeability of the iron.
  • the thickness of the ferromagnetic conductor 376 allows the thickness of the ferromagnetic conductor to be reduced.
  • the thickness of unpurified iron may be approximately 4.5 mm while the thickness of the purified iron is approximately 0.76 mm.
  • electrical conductor 408 provides support for ferromagnetic conductor 376 and the temperature limited heater. Electrical conductor 408 may be made of a material that provides good mechanical strength at temperatures near or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 . In certain embodiments, electrical conductor 408 is a corrosion resistant member. Electrical conductor 408 (support member 378 ) may provide support for ferromagnetic conductor 376 and corrosion resistance. Electrical conductor 408 is made from a material that provides desired electrically resistive heat output at temperatures up to and/or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 .
  • electrical conductor 408 is 347H stainless steel. In some embodiments, electrical conductor 408 is another electrically conductive, good mechanical strength, corrosion resistant material.
  • electrical conductor 408 may be 304H, 316H, 347HH, NF709, Incoloy® 800H alloy (Inco Alloys International, Huntington, W. Va., U.S.A.), Haynes® HR120® alloy, or Inconel® 617 alloy.
  • electrical conductor 408 (support member 378 ) includes different alloys in different portions of the temperature limited heater.
  • a lower portion of electrical conductor 408 (support member 378 ) is 347H stainless steel and an upper portion of the electrical conductor (support member) is NF709.
  • different alloys are used in different portions of the electrical conductor (support member) to increase the mechanical strength of the electrical conductor (support member) while maintaining desired heating properties for the temperature limited heater.
  • ferromagnetic conductor 376 includes different ferromagnetic conductors in different portions of the temperature limited heater. Different ferromagnetic conductors may be used in different portions of the temperature limited heater to vary the Curie temperature and/or the phase transformation temperature range and, thus, the maximum operating temperature in the different portions.
  • the Curie temperature and/or the phase transformation temperature range in an upper portion of the temperature limited heater is lower than the Curie temperature and/or the phase transformation temperature range in a lower portion of the heater. The lower Curie temperature and/or the phase transformation temperature range in the upper portion increases the creep-rupture strength lifetime in the upper portion of the heater.
  • ferromagnetic conductor 376 , electrical conductor 408 , and core 374 are dimensioned so that the skin depth of the ferromagnetic conductor limits the penetration depth of the majority of the flow of electrical current to the support member when the temperature is below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • electrical conductor 408 provides a majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 .
  • the temperature limited heater depicted in FIG. 29 may be smaller because ferromagnetic conductor 376 is thin as compared to the size of the ferromagnetic conductor needed for a temperature limited heater in which the majority of the resistive heat output is provided by the ferromagnetic conductor.
  • the support member and the corrosion resistant member are different members in the temperature limited heater.
  • FIGS. 30 and 31 depict embodiments of temperature limited heaters in which the jacket provides a majority of the heat output below the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • electrical conductor 408 is jacket 370 .
  • Electrical conductor 408 , ferromagnetic conductor 376 , support member 378 , and core 374 (in FIG. 30 ) or inner conductor 362 (in FIG. 31 ) are dimensioned so that the skin depth of the ferromagnetic conductor limits the penetration depth of the majority of the flow of electrical current to the thickness of the jacket.
  • electrical conductor 408 is a material that is corrosion resistant and provides electrically resistive heat output below the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 .
  • electrical conductor 408 is 825 stainless steel or 347H stainless steel.
  • electrical conductor 408 has a small thickness (for example, on the order of 0.5 mm).
  • core 374 is highly electrically conductive material such as copper or aluminum.
  • Support member 378 is 347H stainless steel or another material with good mechanical strength at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 .
  • support member 378 is the core of the temperature limited heater and is 347H stainless steel or another material with good mechanical strength at or near the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 .
  • Inner conductor 362 is highly electrically conductive material such as copper or aluminum.
  • a relatively thin conductive layer is used to provide the majority of the electrically resistive heat output of the temperature limited heater at temperatures up to a temperature at or near the Curie temperature and/or the phase transformation temperature range of the ferromagnetic conductor.
  • a temperature limited heater may be used as the heating member in an insulated conductor heater.
  • the heating member of the insulated conductor heater may be located inside a sheath with an insulation layer between the sheath and the heating member.
  • FIGS. 32A and 32B depict cross-sectional representations of an embodiment of the insulated conductor heater with the temperature limited heater as the heating member.
  • Insulated conductor 410 includes core 374 , ferromagnetic conductor 376 , inner conductor 362 , electrical insulator 364 , and jacket 370 .
  • Core 374 is a copper core.
  • Ferromagnetic conductor 376 is, for example, iron or an iron alloy.
  • Inner conductor 362 is a relatively thin conductive layer of non-ferromagnetic material with a higher electrical conductivity than ferromagnetic conductor 376 .
  • inner conductor 362 is copper.
  • Inner conductor 362 may be a copper alloy. Copper alloys typically have a flatter resistance versus temperature profile than pure copper. A flatter resistance versus temperature profile may provide less variation in the heat output as a function of temperature up to the Curie temperature and/or the phase transformation temperature range.
  • inner conductor 362 is copper with 6% by weight nickel (for example, CuNi6 or LOHMTM).
  • inner conductor 362 is CuNi10Fe1Mn alloy.
  • inner conductor 362 provides the majority of the resistive heat output of insulated conductor 410 below the Curie temperature and/or the phase transformation temperature range.
  • inner conductor 362 is dimensioned, along with core 374 and ferromagnetic conductor 376 , so that the inner conductor provides a desired amount of heat output and a desired turndown ratio.
  • inner conductor 362 may have a cross-sectional area that is around 2 or 3 times less than the cross-sectional area of core 374 .
  • inner conductor 362 has to have a relatively small cross-sectional area to provide a desired heat output if the inner conductor is copper or copper alloy.
  • core 374 has a diameter of 0.66 cm
  • ferromagnetic conductor 376 has an outside diameter of 0.91 cm
  • inner conductor 362 has an outside diameter of 1.03 cm
  • electrical insulator 364 has an outside diameter of 1.53 cm
  • jacket 370 has an outside diameter of 1.79 cm.
  • core 374 has a diameter of 0.66 cm
  • ferromagnetic conductor 376 has an outside diameter of 0.91 cm
  • inner conductor 362 has an outside diameter of 1.12 cm
  • electrical insulator 364 has an outside diameter of 1.63 cm
  • jacket 370 has an outside diameter of 1.88 cm.
  • Such insulated conductors are typically smaller and cheaper to manufacture than insulated conductors that do not use the thin inner conductor to provide the majority of heat output below the Curie temperature and/or the phase transformation temperature range.
  • Electrical insulator 364 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. In certain embodiments, electrical insulator 364 is a compacted powder of magnesium oxide. In some embodiments, electrical insulator 364 includes beads of silicon nitride.
  • a small layer of material is placed between electrical insulator 364 and inner conductor 362 to inhibit copper from migrating into the electrical insulator at higher temperatures.
  • a small layer of nickel for example, about 0.5 mm of nickel may be placed between electrical insulator 364 and inner conductor 362 .
  • Jacket 370 is made of a corrosion resistant material such as, but not limited to, 347 stainless steel, 347H stainless steel, 446 stainless steel, or 825 stainless steel. In some embodiments, jacket 370 provides some mechanical strength for insulated conductor 410 at or above the Curie temperature and/or the phase transformation temperature range of ferromagnetic conductor 376 . In certain embodiments, jacket 370 is not used to conduct electrical current.
  • the hanging stress becomes important in the selection of materials for the temperature limited heater.
  • the support member may not have sufficient mechanical strength (for example, creep-rupture strength) to support the weight of the temperature limited heater at the operating temperatures of the heater.
  • materials for the support member are varied to increase the maximum allowable hanging stress at operating temperatures of the temperature limited heater and, thus, increase the maximum operating temperature of the temperature limited heater. Altering the materials of the support member affects the heat output of the temperature limited heater below the Curie temperature and/or the phase transformation temperature range because changing the materials changes the resistance versus temperature profile of the support member.
  • the support member is made of more than one material along the length of the heater so that the temperature limited heater maintains desired operating properties (for example, resistance versus temperature profile below the Curie temperature and/or the phase transformation temperature range) as much as possible while providing sufficient mechanical properties to support the heater.
  • transition sections are used between sections of the heater to provide strength that compensates for the difference in temperature between sections of the heater.
  • one or more portions of the temperature limited heater have varying outside diameters and/or materials to provide desired properties for the heater.
  • three temperature limited heaters are coupled together in a three-phase wye configuration. Coupling three temperature limited heaters together in the three-phase wye configuration lowers the current in each of the individual temperature limited heaters because the current is split between the three individual heaters. Lowering the current in each individual temperature limited heater allows each heater to have a small diameter. The lower currents allow for higher relative magnetic permeabilities in each of the individual temperature limited heaters and, thus, higher turndown ratios. In addition, there may be no return current path needed for each of the individual temperature limited heaters. Thus, the turndown ratio remains higher for each of the individual temperature limited heaters than if each temperature limited heater had its own return current path.
  • individual temperature limited heaters may be coupled together by shorting the sheaths, jackets, or canisters of each of the individual temperature limited heaters to the electrically conductive sections (the conductors providing heat) at their terminating ends (for example, the ends of the heaters at the bottom of a heater wellbore).
  • the sheaths, jackets, canisters, and/or electrically conductive sections are coupled to a support member that supports the temperature limited heaters in the wellbore.
  • coupling multiple heaters for example, mineral insulated conductor heaters
  • a single power source such as a transformer
  • Coupling multiple heaters to a single transformer may result in using fewer transformers to power heaters used for a treatment area as compared to using individual transformers for each heater.
  • Using fewer transformers reduces surface congestion and allows easier access to the heaters and surface components.
  • Using fewer transformers reduces capital costs associated with providing power to the treatment area.
  • at least 4, at least 5, at least 10, at least 25 heaters, at least 35 heaters, or at least 45 heaters are powered by a single transformer.
  • powering multiple heaters (in different heater wells) from the single transformer may reduce overburden losses because of reduced voltage and/or phase differences between each of the heater wells powered by the single transformer. Powering multiple heaters from the single transformer may inhibit current imbalances between the heaters because the heaters are coupled to the single transformer.
  • the transformer may have to provide power at higher voltages to carry the current to each of the heaters effectively.
  • the heaters are floating (ungrounded) heaters in the formation. Floating the heaters allows the heaters to operate at higher voltages.
  • the transformer provides power output of at least about 3 kV, at least about 4 kV, at least about 5 kV, or at least about 6 kV.
  • FIG. 33 depicts a top view representation of heater 412 with three insulated conductors 410 in conduit 406 .
  • Heater 412 may be located in a heater well in the subsurface formation.
  • Conduit 406 may be a sheath, jacket, or other enclosure around insulated conductors 410 .
  • Each insulated conductor 410 includes core 374 , electrical insulator 364 , and jacket 370 .
  • Insulated conductors 410 may be mineral insulated conductors with core 374 being a copper alloy (for example, a copper-nickel alloy such as Alloy 180), electrical insulator 364 being magnesium oxide, and jacket 370 being Incoloy® 825, copper, or stainless steel (for example 347H stainless steel).
  • jacket 370 includes non-work hardenable metals so that the jacket is annealable.
  • core 374 and/or jacket 370 include ferromagnetic materials.
  • one or more insulated conductors 410 are temperature limited heaters.
  • the overburden portion of insulated conductors 410 include high electrical conductivity materials in core 374 (for example, pure copper or copper alloys such as copper with 3% silicon at a weld joint) so that the overburden portions of the insulated conductors provide little or no heat output.
  • conduit 406 includes non-corrosive materials and/or high strength materials such as stainless steel. In one embodiment, conduit 406 is 347H stainless steel.
  • Insulated conductors 410 may be coupled to the single transformer in a three-phase configuration (for example, a three-phase wye configuration). Each insulated conductor 410 may be coupled to one phase of the single transformer.
  • the single transformer is also coupled to a plurality of identical heaters 412 in other heater wells in the formation (for example, the single transformer may couple to 40 or more heaters in the formation). In some embodiments, the single transformer couples to at least 4, at least 5, at least 10, at least 15, or at least 25 additional heaters in the formation.
  • Electrical insulator 364 ′ may be located inside conduit 406 to electrically insulate insulated conductors 410 from the conduit.
  • electrical insulator 364 ′ is magnesium oxide (for example, compacted magnesium oxide).
  • electrical insulator 364 ′ is silicon nitride (for example, silicon nitride blocks). Electrical insulator 364 ′ electrically insulates insulated conductors 410 from conduit 406 so that at high operating voltages (for example, 3 kV or higher), there is no arcing between the conductors and the conduit.
  • electrical insulator 364 ′ inside conduit 406 has at least the thickness of electrical insulators 364 in insulated conductors 410 .
  • electrical insulator 364 ′ spatially locates insulated conductors 410 inside conduit 406 .
  • FIG. 34 depicts an embodiment of three-phase wye transformer 414 coupled to a plurality of heaters 412 .
  • heaters 412 For simplicity in the drawing, only four heaters 412 are shown in FIG. 34 . It is to be understood that several more heaters may be coupled to the transformer 414 .
  • each leg (each insulated conductor) of each heater is coupled to one phase of transformer 414 and current is returned to the neutral or ground of the transformer (for example, returned through conductor 416 depicted in FIGS. 33 and 35 ).
  • Return conductor 416 may be electrically coupled to the ends of insulated conductors 410 (as shown in FIG. 35 ) current returns from the ends of the insulated conductors to the transformer on the surface of the formation.
  • Return conductor 416 may include high electrical conductivity materials such as pure copper, nickel, copper alloys, or combinations thereof so that the return conductor provides little or no heat output.
  • return conductor 416 is a tubular (for example, a stainless steel tubular) that allows an optical fiber to be placed inside the tubular to be used for temperature and/or other measurement.
  • return conductor 416 is a small insulated conductor (for example, small mineral insulated conductor).
  • Return conductor 416 may be coupled to the neutral or ground leg of the transformer in a three-phase wye configuration.
  • insulated conductors 410 are electrically isolated from conduit 406 and the formation.
  • Using return conductor 416 to return current to the surface may make coupling the heater to a wellhead easier.
  • current is returned using one or more of jackets 370 , depicted in FIG. 33 .
  • One or more jackets 370 may be coupled to cores 374 at the end of the heaters and return current to the neutral of the three-phase wye transformer.
  • FIG. 35 depicts a side view representation of the end section of three insulated conductors 410 in conduit 406 .
  • the end section is the section of the heaters the furthest away from (distal from) the surface of the formation.
  • the end section includes contactor section 418 coupled to conduit 406 . In some embodiments, contactor section 418 is welded or brazed to conduit 406 .
  • Termination 420 is located in contactor section 418 . Termination 420 is electrically coupled to insulated conductors 410 and return conductor 416 . Termination 420 electrically couples the cores of insulated conductors 410 to the return conductor 416 at the ends of the heaters.
  • heater 412 includes an overburden section using copper as the core of the insulated conductors.
  • the copper in the overburden section may be the same diameter as the cores used in the heating section of the heater.
  • the copper in the overburden section may have a larger diameter than the cores in the heating section of the heater. Increasing the size of the copper in the overburden section may decrease losses in the overburden section of the heater.
  • Heaters that include three insulated conductors 410 in conduit 406 , as depicted in FIGS. 33 and 35 may be made in a multiple step process.
  • the multiple step process is performed at the site of the formation or treatment area.
  • the multiple step process is performed at a remote manufacturing site away from the formation. The finished heater is then transported to the treatment area.
  • Insulated conductors 410 may be pre-assembled prior to the bundling either on site or at a remote location. Insulated conductors 410 and return conductor 416 may be positioned on spools. A machine may draw insulated conductors 410 and return conductor 416 from the spools at a selected rate. Preformed blocks of insulation material may be positioned around return conductor 416 and insulated conductors 410 . In an embodiment, two blocks are positioned around return conductor 416 and three blocks are positioned around insulated conductors 410 to form electrical insulator 364 ′. The insulated conductors and return conductor may be drawn or pushed into a plate of conduit material that has been rolled into a tubular shape.
  • the edges of the plate may be pressed together and welded (for example, by laser welding).
  • the conduit may be compacted against the electrical insulator 416 so that all of the components of the heater are pressed together into a compact and tightly fitting form.
  • the electrical insulator may flow and fill any gaps inside the heater.
  • heater 412 (which includes conduit 406 around electrical insulator 364 ′ and the bundle of insulated conductors 410 and return conductor 416 ) is inserted into a coiled tubing tubular that is placed in a wellbore in the formation.
  • the coiled tubing tubular may be left in place in the formation (left in during heating of the formation) or removed from the formation after installation of the heater.
  • the coiled tubing tubular may allow for easier installation of heater 412 into the wellbore.
  • FIG. 36 depicts an embodiment of heater 412 with three insulated cores 374 in conduit 406 .
  • electrical insulator 364 ′ surrounds cores 374 and return conductor 416 in conduit 406 .
  • Cores 374 are located in conduit 406 without an electrical insulator and jacket surrounding the cores.
  • Cores 374 are coupled to the single transformer in a three-phase wye configuration with each core 374 coupled to one phase of the transformer.
  • Return conductor 416 is electrically coupled to the ends of cores 374 and returns current from the ends of the cores to the transformer on the surface of the formation.
  • FIG. 37 depicts an embodiment of heater 412 with three insulated conductors 410 and insulated return conductor in conduit 406 .
  • return conductor 416 is an insulated conductor with core 374 , electrical insulator 364 , and jacket 370 .
  • Return conductor 416 and insulated conductors 410 are located in conduit 406 surrounded by electrical insulator 364 ′.
  • Return conductor 416 and insulated conductors 410 may be the same size or different sizes.
  • Return conductor 416 and insulated conductors 410 operate substantially the same as in the embodiment depicted in FIGS. 33 and 35 .
  • MI cables insulated conductors
  • insulated conductors for use in subsurface applications, such as heating hydrocarbon containing formations in some applications, are longer, may have larger outside diameters, and may operate at higher voltages and temperatures than what is typical in the MI cable industry.
  • the joining of multiple MI cables is needed to make MI cables with sufficient length to reach the depths and distances needed to heat the subsurface efficiently and to join segments with different functions, such as lead-in cables joined to heater sections.
  • Such long heaters also require higher voltages to provide enough power to the farthest ends of the heaters.
  • MI cable splice designs are typically not suitable for voltages above 1000 volts, above 1500 volts, or above 2000 volts and may not operate for extended periods without failure at elevated temperatures, such as over 650° C. (about 1200° F.), over 700° C. (about 1290° F.), or over 800° C. (about 1470° F.).
  • elevated temperatures such as over 650° C. (about 1200° F.), over 700° C. (about 1290° F.), or over 800° C. (about 1470° F.).
  • Such high voltage, high temperature applications typically require the compaction of the mineral insulant in the splice to be as close as possible to or above the level of compaction in the insulated conductor (MI cable) itself.
  • the relatively large outside diameter and long length of MI cables for some applications requires that the cables be spliced while oriented horizontally.
  • These techniques typically use a small hole through which the mineral insulation (such as magnesium oxide powder) is filled into the splice and compacted slightly through vibration and tamping.
  • Such methods do not provide sufficient compaction of the mineral insulation or even allow any compaction of the mineral insulation, and are not suitable for making splices for use at the high voltages needed for these subsurface applications.
  • splices of insulated conductors that are simple yet can operate at the high voltages and temperatures in the subsurface environment over long durations without failure.
  • the splices may need higher bending and tensile strengths to inhibit failure of the splice under the weight loads and temperatures that the cables can be subjected to in the subsurface.
  • Techniques and methods also may be utilized to reduce electric field intensities in the splices so that leakage currents in the splices are reduced and to increase the margin between the operating voltage and electrical breakdown. Reducing electric field intensities may help increase voltage and temperature operating ranges of the splices.
  • FIG. 38 depicts a side view cross-sectional representation of one embodiment of a fitting for joining insulated conductors.
  • Fitting 422 is a splice or coupling joint for joining insulated conductors 410 A, 410 B.
  • fitting 422 includes sleeve 424 and housings 426 A, 426 B.
  • Housings 426 A, 426 B may be splice housings, coupling joint housings, coupler housings.
  • Sleeve 424 and housings 426 A, 426 B may be made of mechanically strong, electrically conductive materials such as, but not limited to, stainless steel.
  • Sleeve 424 and housings 426 A, 426 B may be cylindrically shaped or polygon shaped.
  • Sleeve 424 and housings 426 A, 426 B may have rounded edges, tapered diameter changes, other features, or combinations thereof, which may reduce electric field intensities in fitting 422 .
  • Fitting 422 may be used to couple (splice) insulated conductor 410 A to insulated conductor 410 B while maintaining the mechanical and electrical integrity of the jackets (sheaths), insulation, and cores (conductors) of the insulated conductors.
  • Fitting 422 may be used to couple heat producing insulated conductors with non-heat producing insulated conductors, to couple heat producing insulated conductors with other heat producing insulated conductors, or to couple non-heat producing insulated conductors with other non-heat producing insulated conductors.
  • more than one fitting 422 is used in to couple multiple heat producing and non-heat producing insulated conductors to produce a long insulated conductor.
  • Fitting 422 may be used to couple insulated conductors with different diameters, as shown in FIG. 38 .
  • the insulated conductors may have different core (conductor) diameters, different jacket (sheath) diameters, or combinations of different diameters.
  • Fitting 422 may also be used to couple insulated conductors with different metallurgies, different types of insulation, or a combination thereof.
  • housing 426 A is coupled to jacket (sheath) 370 A of insulated conductor 410 A and housing 426 B is coupled to jacket 370 B of insulated conductor 410 B.
  • housings 426 A, 426 B are welded, brazed, or otherwise permanently affixed to insulated conductors 410 A, 410 B.
  • housings 426 A, 426 B are temporarily or semi-permanently affixed to jackets 370 A, 370 B of insulated conductors 410 A, 410 B (for example, coupled using threads or adhesives). Fitting 422 may be centered between the end portions of the insulated conductors 410 A, 410 B.
  • the interior volumes of sleeve 424 and housings 426 A, 426 B are substantially filled with electrically insulating material 430 .
  • substantially filled refers to entirely or almost entirely filling the volume or volumes with electrically insulating material with substantially no macroscopic voids in the volume or volumes.
  • substantially filled may refer to filling almost the entire volume with electrically insulating material that has some porosity because of microscopic voids (for example, up to about 40% porosity).
  • Electrically insulating material 430 may be magnesium oxide, other electrical insulators such as ceramic powders (for example, boron nitride), a mixture of magnesium oxide and another electrical insulator (for example, up to about 50% by volume boron nitride), ceramic cement, mixtures of ceramic powders with certain non-ceramic materials, or mixtures thereof.
  • ceramic powders for example, boron nitride
  • another electrical insulator for example, up to about 50% by volume boron nitride
  • ceramic cement for example, up to about 50% by volume boron nitride
  • magnesium oxide may be mixed with boron nitride or another electrical insulator to improve the ability of the electrically insulating material to flow or to improve the dielectric characteristics of the electrically insulating material.
  • electrically insulating material 430 is material similar to electrical insulation used inside of at least one of insulated conductors 410 A, 410 B. Electrically insulating material 430 may have substantially similar dielectric characteristics
  • first sleeve 424 and housings 426 A, 426 B are made up (for example, put together or manufactured) buried or submerged in electrically insulating material 430 .
  • Making up sleeve 424 and housings 426 A, 426 B buried in electrically insulating material 430 inhibits open space from forming in the interior volumes of the portions.
  • Sleeve 424 and housings 426 A, 426 B have open ends to allow insulated conductors 410 A, 410 B to pass through. These open ends may be sized to have diameters slightly larger than the outside diameter of the jackets of the insulated conductors.
  • cores 374 A, 374 B of insulated conductors 410 A, 410 B are joined together at coupling 428 .
  • the jackets and insulation of insulated conductors 410 A, 410 B may be cut back or stripped to expose desired lengths of cores 374 A, 374 B before joining the cores.
  • Coupling 428 may be located in electrically insulating material 430 inside sleeve 424 . Coupling 428 may join cores 374 A, 374 B together, for example, by compression, crimping, brazing, welding, or other techniques known in the art.
  • insulated conductors 410 A, 410 B are coupled using fitting 422 by first sliding housing 426 A over jacket 370 A of insulated conductor 410 A and, second, sliding housing 426 B over jacket 370 B of insulated conductor 410 B.
  • the housings are slid over the jackets with the large diameter ends of the housings facing the ends of the insulated conductors.
  • Sleeve 424 may be slid over insulated conductor 410 B such that it is adjacent to housing 426 B.
  • Cores 374 A, 374 B are joined at coupling 428 to create a robust electrical and mechanical connection between the cores.
  • the small diameter end of housing 426 A is joined (for example, welded) to jacket 370 A of insulated conductor 410 A.
  • Sleeve 424 and housing 426 B are brought (moved or pushed) together with housing 426 A to form fitting 422 .
  • the interior volume of fitting 422 may be substantially filled with electrically insulating material while the sleeve and the housings are brought together.
  • the interior volume of the combined sleeve and housings is reduced such that the electrically insulating material substantially filling the entire interior volume is compacted.
  • Sleeve 424 is joined to housing 426 B and housing 426 B is joined to jacket 370 B of insulated conductor 410 B.
  • the volume of sleeve 424 may be further reduced, if additional compaction is desired.
  • the interior volumes of housings 426 A, 426 B filled with electrically insulating material 430 have tapered shapes.
  • the diameter of the interior volumes of housings 426 A, 426 B may taper from a smaller diameter at or near the ends of the housings coupled to insulated conductors 410 A, 410 B to a larger diameter at or near the ends of the housings located inside sleeve 424 (the ends of the housings facing each other or the ends of the housings facing the ends of the insulated conductors).
  • the tapered shapes of the interior volumes may reduce electric field intensities in fitting 422 . Reducing electric field intensities in fitting 422 may reduce leakage currents in the fitting at increased operating voltages and temperatures, and may increase the margin to electrical breakdown. Thus, reducing electric field intensities in fitting 422 may increase the range of operating voltages and temperatures for the fitting.
  • the insulation from insulated conductors 410 A, 410 B tapers from jackets 370 A, 370 B down to cores 374 A, 374 B in the direction toward the center of fitting 422 in the event that the electrically insulating material 430 is a weaker dielectric than the insulation in the insulated conductors.
  • the insulation from insulated conductors 410 A, 410 B tapers from jackets 370 A, 370 B down to cores 374 A, 374 B in the direction toward the insulated conductors in the event that electrically insulating material 430 is a stronger dielectric than the insulation in the insulated conductors. Tapering the insulation from the insulated conductors reduces the intensity of electric fields at the interfaces between the insulation in the insulated conductors and the electrically insulating material within the fitting.
  • FIG. 39 depicts a tool that may be used to cut away part of the inside of insulated conductors 410 A, 410 B (for example, electrical insulation inside the jacket of the insulated conductor).
  • Cutting tool 436 may include cutting teeth 438 and drive tube 440 .
  • Drive tube 440 may be coupled to the body of cutting tool 436 using, for example, a weld or braze. In some embodiments, no cutting tool is needed to cut away electrical insulation from inside the jacket.
  • Sleeve 424 and housings 426 A, 426 B may be coupled together using any means known in the art such as brazing, welding, or crimping. In some embodiments, in the embodiment shown in FIG. 40 , sleeve 424 and housings 426 A, 426 B have threads that engage to couple the pieces together.
  • electrically insulating material 430 is compacted during the assembly process.
  • the force to press the housings 426 A, 426 B toward each other may put a pressure on electrically insulating material 430 of at least 25,000 pounds per square inch, or between 25,000 and 55,000 pounds per square inch, in order to provide acceptable compaction of the insulating material.
  • the tapered shapes of the interior volumes of housings 426 A, 426 B and the make-up of electrically insulating material 430 may enhance compaction of the electrically insulating material during the assembly process to the point where the dielectric characteristics of the electrically insulating material are, to the extent practical, comparable to that within insulated conductors 410 A, 410 B.
  • Methods and devices to facilitate compaction include, but are not limited to, mechanical methods (such as shown in FIG. 43 ), pneumatic, hydraulic (such as shown in FIGS. 44 and 45 ), swaged, or combinations thereof.
  • vibration and/or tamping of electrically insulating material 430 may also be used to consolidate the electrically insulating material. Vibration (and/or tamping) may be applied either at the same time as application of force to push the housings 426 A, 426 B together, or vibration (and/or tamping) may be alternated with application of such force. Vibration and/or tamping may reduce bridging of particles in electrically insulating material 430 .
  • electrically insulating material 430 inside housings 426 A, 426 B is compressed mechanically by tightening nuts 434 against ferrules 432 coupled to jackets 370 A, 370 B.
  • the mechanical method compacts the interior volumes of housings 426 A, 426 B because of the tapered shape of the interior volumes.
  • Ferrules 432 may be copper or other soft metal ferrules.
  • Nuts 434 may be stainless steel or other hard metal nut that is movable on jackets 370 A, 370 B. Nuts 434 may engage threads on housings 426 A, 426 B to couple to the housings.
  • nuts 434 and ferrules 432 work to compress the interior volumes of the housings.
  • nuts 434 and ferrules 432 may work to move housings 426 A, 426 B further onto sleeve 424 (using the threaded coupling between the pieces) and compact the interior volume of the sleeve.
  • housings 426 A, 426 B and sleeve 424 are coupled together using the threaded coupling before the nut and ferrule are swaged down on the second portion. As the interior volumes inside housings 426 A, 426 B are compressed, the interior volume inside sleeve 424 may also be compressed.
  • nuts 434 and ferrules 432 may act to couple housings 426 A, 426 B to insulated conductors 410 A, 410 B.
  • multiple insulated conductors are spliced together in an end fitting.
  • three insulated conductors may be spliced together in an end fitting to couple electrically the insulated conductors in a 3-phase wye configuration.
  • FIG. 41A depicts a side view of a cross-sectional representation of an embodiment of threaded fitting 442 for coupling three insulated conductors 410 A, 410 B, 410 C.
  • FIG. 41B depicts a side view of a cross-sectional representation of an embodiment of welded fitting 442 for coupling three insulated conductors 410 A, 410 B, 410 C. As shown in FIGS.
  • insulated conductors 410 A, 410 B, 410 C may be coupled to fitting 442 through end cap 444 .
  • End cap 444 may include three strain relief fittings 446 through which insulated conductors 410 A, 410 B, 410 C pass.
  • Cores 374 A, 374 B, 374 C of the insulated conductors may be coupled together at coupling 428 .
  • Coupling 428 may be, for example, a braze (such as a silver braze or copper braze), a welded joint, or a crimped joint.
  • Coupling cores 374 A, 374 B, 374 C at coupling 428 electrically join the three insulated conductors for use in a 3-phase wye configuration.
  • end cap 444 may be coupled to main body 448 of fitting 442 using threads. Threading of end cap 444 and main body 448 may allow the end cap to compact electrically insulating material 430 inside the main body.
  • cover 450 At the end of main body 448 opposite of end cap 444 is cover 450 .
  • Cover 450 may also be attached to main body 448 by threads. In certain embodiments, compaction of electrically insulating material 430 in fitting 442 is enhanced through tightening of cover 450 into main body 448 , by crimping of the main body after attachment of the cover, or a combination of these methods.
  • end cap 444 may be coupled to main body 448 of fitting 442 using welding, brazing, or crimping. End cap 444 may be pushed or pressed into main body 448 to compact electrically insulating material 430 inside the main body.
  • Cover 450 may also be attached to main body 448 by welding, brazing, or crimping. Cover 450 may be pushed or pressed into main body 448 to compact electrically insulating material 430 inside the main body. Crimping of the main body after attachment of the cover may further enhance compaction of electrically insulating material 430 in fitting 442 .
  • plugs 452 close openings or holes in cover 450 .
  • the plugs may be threaded, welded, or brazed into openings in cover 450 .
  • the openings in cover 450 may allow electrically insulating material 430 to be provided inside fitting 442 when cover 450 and end cap 444 are coupled to main body 448 .
  • the openings in cover 450 may be plugged or covered after electrically insulating material 430 is provided inside fitting 442 .
  • openings are located on main body 448 of fitting 442 . Openings on main body 448 may be plugged with plugs 452 or other plugs.
  • cover 450 includes one or more pins.
  • the pins are or are part of plugs 452 .
  • the pins may engage a torque tool that turns cover 450 and tightens the cover on main body 448 .
  • An example of torque tool 454 that may engage the pins is depicted in FIG. 42 .
  • Torque tool 454 may have an inside diameter that substantially matches the outside diameter of cover 450 (depicted in FIG. 41A ). As shown in FIG. 42 , torque tool 454 may have slots or other depressions that are shaped to engage the pins on cover 450 .
  • Torque tool 454 may include recess 456 .
  • Recess 456 may be a square drive recess or other shaped recess that allows operation (turning) of the torque tool.
  • FIG. 43 depicts an embodiment of clamp assemblies 458 A,B that may be used to mechanically compact fitting 422 .
  • Clamp assemblies 458 A,B may be shaped to secure fitting 422 in place at the shoulders of housings 426 A, 426 B.
  • Threaded rods 462 may pass through holes 460 of clamp assemblies 458 A,B.
  • Nuts 468 , along with washers, on each of threaded rods 462 may be used to apply force on the outside faces of each clamp assembly and bring the clamp assemblies together such that compressive forces are applied to housings 426 A, 426 B of fitting 422 . These compressive forces compact electrically insulating material inside fitting 422 .
  • clamp assemblies 458 are used in hydraulic, pneumatic, or other compaction methods.
  • FIG. 44 depicts an exploded view of an embodiment of hydraulic compaction machine 464 .
  • FIG. 45 depicts a representation of an embodiment of assembled hydraulic compaction machine 464 .
  • clamp assemblies 458 may be used to secure fitting 422 (depicted, for example, in FIG. 38 ) in place with insulated conductors coupled to the fitting.
  • At least one clamp assembly (for example, clamp assembly 458 A) may be moveable together to compact the fitting in the axial direction.
  • Power unit 466 shown in FIG. 44 , may be used to power compaction machine 464 .
  • FIG. 46 depicts an embodiment of fitting 422 and insulated conductors 410 A, 410 B secured in clamp assembly 458 A and clamp assembly 458 B before compaction of the fitting and insulated conductors.
  • the cores of insulated conductors 410 A, 410 B are coupled using coupling 428 at or near the center of sleeve 424 .
  • Sleeve 424 is slid over housing 426 A, which is coupled to insulated conductor 410 A.
  • Sleeve 424 and housing 426 A are secured in fixed (non-moving) clamp assembly 458 B. Insulated conductor 410 B passes through housing 426 B and movable clamp assembly 458 A.
  • Insulated conductor 410 B may be secured by another clamp assembly fixed relative to clamp assembly 458 B (not shown). Clamp assembly 458 A may be moved towards clamp assembly 458 B to couple housing 426 B to sleeve 424 and compact electrically insulating material inside the housings and the sleeve. Interfaces between insulated conductor 410 A and housing 426 A, between housing 426 A and sleeve 424 , between sleeve 424 and housing 426 B, and between housing 426 B and insulated conductor 410 B may then be coupled by welding, brazing, or other techniques known in the art.
  • FIG. 47 depicts a side view representation of an embodiment of fitting 470 for joining insulated conductors.
  • Fitting 470 may be a cylinder or sleeve that has sufficient clearance between the inside diameter of the sleeve and the outside diameters of insulated conductors 410 A, 410 B such that the sleeve fits over the ends of the insulated conductors.
  • the cores of insulated conductors 410 A, 410 B may be joined inside fitting 470 .
  • the jackets and insulation of insulated conductors 410 A, 410 B may be cut back or stripped to expose desired lengths of the cores before joining the cores.
  • Fitting 470 may be centered between the end portions of insulated conductors 410 A, 410 B.
  • Fitting 470 may be used to couple insulated conductor 410 A to insulated conductor 410 B while maintaining the mechanical and electrical integrity of the jackets, insulation, and cores of the insulated conductors. Fitting 470 may be used to couple heat producing insulated conductors with non-heat producing insulated conductors, to couple heat producing insulated conductors with other heat producing insulated conductors, or to couple non-heat producing insulated conductors with other non-heat producing insulated conductors. In some embodiments, more than one fitting 470 is used in to couple multiple heat producing and non-heat producing insulated conductors to produce a long insulated conductor.
  • Fitting 470 may be used to couple insulated conductors with different diameters.
  • the insulated conductors may have different core diameters, different jacket diameters, or combinations of different diameters.
  • Fitting 470 may also be used to couple insulated conductors with different metallurgies, different types of insulation, or a combination thereof.
  • fitting 470 has at least one angled end.
  • the ends of fitting 470 may be angled relative to the longitudinal axis of the fitting. The angle may be, for example, about 45° or between 30° and 60°.
  • the ends of fitting 470 may have substantially elliptical cross-sections.
  • the substantially elliptical cross-sections of the ends of fitting 470 provide a larger area for welding or brazing of the fitting to insulated conductors 410 A, 410 B.
  • the larger coupling area increases the strength of spliced insulated conductors.
  • the angled ends of fitting 470 give the fitting a substantially parallelogram shape.
  • fitting 470 provides higher tensile strength and higher bending strength for the fitting than if the fitting had straight ends by distributing loads along the fitting.
  • Fitting 470 may be oriented so that when insulated conductors 410 A, 410 B and the fitting are spooled (for example, on a coiled tubing installation), the angled ends act as a transition in stiffness from the fitting body to the insulated conductors. This transition reduces the likelihood of the insulated conductors to kink or crimp at the end of the fitting body.
  • fitting 470 includes opening 472 .
  • Opening 472 allows electrically insulating material (such as electrically insulating material 430 , depicted in FIG. 38 ) to be provided (filled) inside fitting 470 .
  • Opening 472 may be a slot or other longitudinal opening extending along part of the length of fitting 470 .
  • opening 472 extends substantially the entire gap between the ends of insulated conductors 410 A, 410 B inside fitting 470 .
  • Opening 472 allows substantially the entire volume (area) between insulated conductors 410 A, 410 B, and around any welded or spliced joints between the insulated conductors, to be filled with electrically insulating material without the insulating material having to be moved axially toward the ends of the volume between the insulated conductors.
  • the width of opening 472 allows electrically insulating material to be forced into the opening and packed more tightly inside fitting 470 , thus, reducing the amount of void space inside the fitting.
  • Electrically insulating material may be forced through the slot into the volume between insulated conductors 410 A, 410 B, for example, with a tool with the dimensions of the slot. The tool may be forced into the slot to compact the insulating material.
  • the electrically insulating material may be further compacted inside fitting 470 using vibration, tamping, or other techniques. Further compacting the electrically insulating material may more uniformly distribute the electrically insulating material inside fitting 470 .
  • opening 472 may be closed.
  • an insert or other covering may be placed over the opening and secured in place.
  • FIG. 48 depicts a side view representation of an embodiment of fitting 470 with opening 472 covered with insert 474 .
  • Insert 474 may be welded or brazed to fitting 470 to close opening 472 .
  • insert 474 is ground or polished so that the insert if flush on the surface of fitting 470 .
  • welds or brazes 476 may be used to secure fitting 470 to insulated conductors 410 A, 410 B.
  • fitting 470 may be compacted mechanically, hydraulically, pneumatically, or using swaging methods to compact further the electrically insulating material inside the fitting. Further compaction of the electrically insulating material reduces void volume inside fitting 470 and reduces the leakage currents through the fitting and increases the operating range of the fitting (for example, the maximum operating voltages or temperatures of the fitting).
  • fitting 470 includes certain features that may further reduce electric field intensities inside the fitting.
  • fitting 470 or coupling 428 of the cores of the insulated conductors inside the fitting may include tapered edges, rounded edges, or other smoothed out features to reduce electric field intensities.
  • FIG. 49 depicts an embodiment of fitting 470 with electric field reducing features at coupling 428 between insulated conductors 410 A, 410 B.
  • coupling 428 is a welded joint with a smoothed out or rounded profile to reduce electric field intensity inside fitting 470 .
  • fitting 470 has a tapered interior volume to increase the volume of electrically insulating material inside the fitting. Having the tapered and larger volume may reduce electric field intensities inside fitting 470 .
  • electric field stress reducers may be located inside fitting 470 to decrease the electric field intensity.
  • FIG. 50 depicts an embodiment of electric field stress reducer 478 .
  • Reducer 478 may be located in the interior volume of fitting 470 (shown in FIG. 49 ).
  • Reducer 478 may be a split ring or other separable piece so that the reducer can be fitted around cores 374 A, 374 B of insulated conductors 410 A, 410 B after they are joined (shown in FIG. 49 ).
  • fittings depicted herein may form robust electrical and mechanical connections between insulated conductors.
  • fittings depicted herein may be suitable for extended operation at voltages above 1000 volts, above 1500 volts, or above 2000 volts and temperatures of at least about 650° C., at least about 700° C., at least about 800° C.
  • three insulated conductor heaters are coupled together into a single assembly.
  • the single assembly may be built in long lengths and may operate at high voltages (for example, voltages of 4000 V nominal).
  • the individual insulated conductor heaters are enclosed in corrosive resistant jackets to resist damage from the external environment.
  • the jackets may be, for example, seam welded stainless steel armor similar to that used on type MC/CWCMC cable.
  • three insulated conductor heaters are cabled and the insulating filler added in conventional methods known in the art.
  • the insulated conductor heaters may include one or more heater sections that resistively heat and provide heat to formation adjacent to the heater sections.
  • the insulated conductors may include one or more other sections that provide electricity to the heater sections with relatively small heat loss.
  • the individual insulated conductor heaters may be wrapped with high temperature fiber tapes before being placed on a take-up reel (for example, a coiled tubing rig). The reel assembly may be moved to another machine for application of an outer metallic sheath or outer protective conduit.
  • the fillers include glass, ceramic or other temperature resistant fibers that withstand operating temperature of 760° C. or higher.
  • the insulated conductor cables may be wrapped in multiple layers of a ceramic fiber woven tape material. By wrapping the tape around the cabled insulated conductor heaters prior to application of the outer metallic sheath, electrical isolation is provided between the insulated conductor heaters and the outer sheath. This electrical isolation inhibits leakage current from the insulated conductor heaters passing into the subsurface formation and forces any leakage currents to return directly to the power source on the individual insulated conductor sheaths and/or on a lead-in conductor or lead-out conductor coupled to the insulated conductors.
  • the lead-in or lead-out conductors may be coupled to the insulated conductors when the insulated conductors are placed into an assembly with the outer metallic sheath.
  • the insulated conductor heaters are wrapped with a metallic tape or other type of tape instead of the high temperature ceramic fiber woven tape material.
  • the metallic tape holds the insulated conductor heaters together.
  • a widely-spaced wide pitch spiral wrapping of a high temperature fiber rope may be wrapped around the insulated conductor heaters.
  • the fiber rope may provide electrical isolation between the insulated conductors and the outer sheath.
  • the fiber rope may be added at any stage during assembly. For example, the fiber rope may be added as a part of the final assembly when the outer sheath is added.
  • Application of the fiber rope may be simpler than other electrical isolation methods because application of the fiber rope is done with only a single layer of rope instead of multiple layers of ceramic tape.
  • the fiber rope may be less expensive than multiple layers of ceramic tape.
  • the fiber rope may increase heat transfer between the insulated conductors and the outer sheath and/or reduce interference with any welding process used to weld the outer sheath around the insulated conductors (for example, seam welding).
  • an insulated conductor or another type of heater is installed in a wellbore or opening in the formation using outer tubing coupled to a coiled tubing rig.
  • FIG. 51 depicts outer tubing 480 partially unspooled from coiled tubing rig 482 .
  • Outer tubing 480 may be made of metal or polymeric material.
  • Outer tubing 480 may be a flexible conduit such as, for example, a tubing guide string or other coiled tubing string.
  • Heater 412 may be pushed into outer tubing 480 , as shown in FIG. 52 . In certain embodiments, heater 412 is pushed into outer tubing 480 by pumping the heater into the outer tubing.
  • one or more flexible cups 484 are coupled to the outside of heater 412 .
  • Flexible cups 484 may have a variety of shapes and/or sizes but typically are shaped and sized to maintain at least some pressure inside at least a portion of outer tubing 480 as heater 412 is pushed or pumped into the outer tubing.
  • Flexible cups 484 are made of flexible materials such as, but not limited to, elastomeric materials.
  • flexible cups 484 may have flexible edges that provide limited mechanical resistance as heater 412 is pushed into outer tubing 480 but remain in contact with the inner walls of outer tubing 480 as the heater is pushed so that pressure is maintained between the heater and the outer tubing.
  • Maintaining at least some pressure in outer tubing 480 between flexible cups 484 allows heater 412 to be continuously pushed into the outer tubing with lower pump pressures. Without flexible cups 484 , higher pressures may be needed to push heater 412 into outer tubing 480 . In some embodiments, cups 484 allow some pressure to be released while maintaining pressure in outer tubing 480 . In certain embodiments, flexible cups 484 are spaced to distribute pumping forces optimally along heater 412 inside outer tubing 480 . For example, flexible cups 484 may be evenly spaced along heater 412 .
  • Heater 412 is pushed into outer tubing 480 until the heater is fully inserted into the outer tubing, as shown in FIG. 53 .
  • Drilling guide 486 may be coupled to the end of heater 412 .
  • Heater 412 , outer tubing 480 , and drilling guide 486 may be spooled onto coiled tubing rig 482 , as shown in FIG. 54 .
  • the assembly may be transported to a location for installation of the heater. For example, the assembly may be transported to the location of a subsurface heater wellbore (opening).
  • FIG. 55 depicts coiled tubing rig 482 being used to install heater 412 and outer tubing 480 into opening 386 using drilling guide 486 .
  • opening 386 is an L-shaped opening or wellbore with a substantially horizontal or inclined portion in a hydrocarbon containing layer of the formation.
  • heater 412 has a heating section that is placed in the substantially horizontally or inclined portion of opening 386 to be used to heat the hydrocarbon containing layer.
  • opening 386 has a horizontal or inclined section that is at least about 1000 m in length, at least about 1500 m in length, or at least about 2000 m in length.
  • Overburden casing 398 may be located around the outer walls of opening 386 in an overburden section of the formation.
  • drilling fluid is left in opening 386 after the opening has been completed (the opening has been drilled).
  • FIG. 56 depicts heater 412 and outer tubing 480 installed in opening 386 .
  • Gap 488 may be left at or near the far end of heater 412 and outer tubing 480 .
  • Gap 488 may allow for heater expansion in opening 386 after the heater is energized.
  • FIG. 57 depicts outer tubing 480 being removed from opening 386 while leaving heater 412 installed in the opening.
  • Outer tubing 480 is spooled back onto coiled tubing rig 482 as the outer tubing is pulled off heater 412 .
  • outer tubing 480 is pumped down to balance pressure between opening 386 and the outer tubing. Balancing the pressure allows outer tubing 480 to be pulled off heater 412 .
  • FIG. 58 depicts outer tubing 480 used to provide packing material 402 into opening 386 .
  • the outer tubing may be used to provide packing material into the opening.
  • the shoe of opening 386 may be located at or near the bottom of overburden casing 398 .
  • Packing material 402 may be provided (for example, pumped) through outer tubing 480 and out the end of the outer tubing at the shoe of opening 386 .
  • Packing material 402 is provided into opening 386 to seal off the opening around heater 412 .
  • Packing material 402 provides a barrier between the overburden section and the heating section of opening 386 .
  • packing material 402 is cement or another suitable plugging material.
  • outer tubing 480 is continuously spooled while packing material 402 is provided into opening 386 .
  • Outer tubing 480 may be spooled slowly while packing material 402 is provided into opening 386 to allow the packing material to settle into the opening properly.
  • outer tubing 480 is spooled further onto coiled tubing rig 482 , as shown in FIG. 59 .
  • FIG. 60 depicts outer tubing 480 spooled onto coiled tubing rig 482 with heater 412 installed in opening 386 .
  • flexible cups 484 are spaced in the portion of opening 386 with overburden casing 398 to facilitate adequate stand-off of heater 412 in the overburden portion of the opening.
  • Flexible cups 484 may electrically insulate heater 412 from overburden casing 398 .
  • flexible cups 484 may space apart heater 412 and overburden casing 398 such that they are not in physical contact with each other.
  • outer tubing 480 is removed from opening 386 , wellhead 392 and/or other completions may be installed at the surface of the opening, as shown in FIG. 61 .
  • heater 412 is energized to begin heating
  • flexible cups 484 may begin to burn or melt off. In some embodiments, flexible cups 484 begin to burn or melt off at low temperatures during early stages of the heating process.
  • FIG. 62 depicts an embodiment of a heater in wellbore 490 in formation 492 .
  • the heater includes insulated conductor 410 in conduit 382 with material 494 between the insulated conductor and the conduit.
  • insulated conductor 410 is a mineral insulated conductor. Electricity supplied to insulated conductor 410 resistively heats the insulated conductor. Insulated conductor conductively transfers heat to material 494 . Heat may transfer within material 494 by heat conduction and/or by heat convection. Radiant heat from insulated conductor 410 and/or heat from material 494 transfers to conduit 382 . Heat may transfer to the formation from the heater by conductive or radiative heat transfer from conduit 382 .
  • Material 494 may be molten metal, molten salt, or other liquid.
  • a gas for example, nitrogen, carbon dioxide, and/or helium
  • the gas may inhibit oxidation or other chemical changes of material 494 .
  • the gas may inhibit vaporization of material 494 .
  • Insulated conductor 410 and conduit 382 may be placed in an opening in a subsurface formation. Insulated conductor 410 and conduit 382 may have any orientation in a subsurface formation (for example, the insulated conductor and conduit may be substantially vertical or substantially horizontally oriented in the formation). Insulated conductor 410 includes core 374 , electrical insulator 364 , and jacket 370 . In some embodiments, core 374 is a copper core. In some embodiments, core 374 includes other electrical conductors or alloys (for example, copper alloys). In some embodiments, core 374 includes a ferromagnetic conductor so that insulated conductor 410 operates as a temperature limited heater. In some embodiments, core 374 does not include a ferromagnetic conductor.
  • core 374 of insulated conductor 410 is made of two or more portions.
  • the first portion may be placed adjacent to the overburden.
  • the first portion may be sized and/or made of a highly conductive material so that the first portion does not resistively heat to a high temperature.
  • One or more other portions of core 410 may be sized and/or made of material that resistively heats to a high temperature. These portions of core 410 may be positioned adjacent to sections of the formation that are to be heated by the heater.
  • the insulated conductor does not include a highly conductive first portion.
  • a lead in cable may be coupled to the insulated conductor to supply electricity to the insulated conductor.
  • core 374 of insulated conductor 410 is a highly conductive material such as copper. Core 374 may be electrically coupled to jacket 370 at or near the end of the insulated conductor. In some embodiments, insulated conductor 410 is electrically coupled to conduit 382 . Electrical current supplied to insulated conductor 410 may resistively heat core 374 , jacket 370 , material 494 , and/or conduit 382 . Resistive heating of core 374 , jacket 370 , material 494 , and/or conduit 382 generates heat that may transfer to the formation.
  • Electrical insulator 364 may be magnesium oxide, aluminum oxide, silicon dioxide, beryllium oxide, boron nitride, silicon nitride, or combinations thereof. In certain embodiments, electrical insulator 364 is a compacted powder of magnesium oxide. In some embodiments, electrical insulator 364 includes beads of silicon nitride. In certain embodiments, a thin layer of material clad over core 374 to inhibit the core from migrating into the electrical insulator at higher temperatures (i.e., to inhibit copper of the core from migrating into magnesium oxide of the insulation). For example, a small layer of nickel (for example, about 0.5 mm of nickel) may be clad on core 374 .
  • material 494 may be relatively corrosive.
  • Jacket 370 and/or at least the inside surface of conduit 382 may be made of a corrosion resistant material such as, but not limited to, nickel, Alloy N (Carpenter Metals), 347 stainless steel, 347H stainless steel, 446 stainless steel, or 825 stainless steel.
  • conduit 382 may be plated or lined with nickel.
  • material 494 may be relatively non-corrosive.
  • Jacket 370 and/or at least the inside surface of conduit 382 may be made of a material such as carbon steel.
  • jacket 370 of insulated conductor 410 is not used as the main return of electrical current for the insulated conductor.
  • material 494 is a good electrical conductor such as a molten metal
  • current returns through the molten metal in the conduit and/or through the conduit 382 .
  • conduit 382 is made of a ferromagnetic material, (for example 410 stainless steel). Conduit 382 may function as a temperature limited heater until the temperature of the conduit approaches, reaches or exceeds the Curie temperature or phase transition temperature of the conduit material.
  • material 494 returns electrical current to the surface from insulated conductor 410 (i.e., the material acts as the return or ground conductor for the insulated conductor).
  • Material 494 may provide a current path with low resistance so that a long insulated conductor 410 is useable in conduit 382 .
  • the long heater may operate at low voltages for the length of the heater due to the presence of material 494 that is conductive.
  • FIG. 63 depicts an embodiment of a portion of insulated conductor 410 in conduit 382 wherein material 494 is a good conductor (for example, a liquid metal) and current flow is indicated by the arrows.
  • Current flows down core 374 and returns through jacket 370 , material 494 , and conduit 382 .
  • Jacket 370 and conduit 382 may be at approximately constant potential.
  • Current flows radially from jacket 370 to conduit 382 through material 494 .
  • Material 494 may resistively heat. Heat from material 494 may transfer through conduit 382 into the formation.
  • material 494 is partially electrically conductive (for example, the material is a molten salt)
  • current returns mainly through jacket 370 . All or a portion of the current that passes through partially conductive material 494 may pass to ground through conduit 382 .
  • core 374 of insulated conductor 410 has a diameter of about 1 cm
  • electrical insulator 364 has an outside diameter of about 1.6 cm
  • jacket 370 has an outside diameter of about 1.8 cm.
  • the insulated conductor is smaller.
  • core 374 has a diameter of about 0.5 cm
  • electrical insulator 364 has an outside diameter of about 0.8 cm
  • jacket 370 has an outside diameter of about 0.9 cm.
  • Other insulated conductor geometries may be used.
  • the smaller geometry of insulated conductor 410 may result in a higher operating temperature of the insulated conductor to achieve the same temperature at the conduit.
  • the smaller geometry insulated conductors may be significantly more economically favorable due to manufacturing cost, weight, and other factors.
  • Material 494 may be placed between the outside surface of insulated conductor 410 and the inside surface of conduit 382 .
  • material 494 is placed in the conduit in a solid form as balls or pellets. Material 494 may melt below the operating temperatures of insulated conductor 410 . Material may melt above ambient subsurface formation temperatures.
  • Material 494 may be placed in conduit 382 after insulated conductor 410 is placed in the conduit.
  • material 494 is placed in conduit 410 as a liquid. The liquid may be placed in conduit 382 before or after insulated conductor 410 is placed in the conduit (for example, the molten liquid may be poured into the conduit before or after the insulated conductor is placed in the conduit).
  • material 494 may be placed in conduit 382 before or after insulated conductor 410 is energized (i.e., supplied with electricity). Material 494 may be added to conduit 382 or removed from the conduit after operation of the heater is initialized. Material 494 may be added to or removed from conduit 382 to maintain a desired head of fluid in the conduit. In some embodiments, the amount of material 494 in conduit 382 may be adjusted (i.e., added to or depleted) to adjust or balance the stresses on the conduit. Material 494 may inhibit deformation of conduit 382 . The head of material 494 in conduit 382 may inhibit the formation from crushing or otherwise deforming the conduit should the formation expand against the conduit. The head of fluid in conduit 382 allows the wall of the conduit to be relatively thin. Having thin conduits 382 may increase the economic viability of using multiple heaters of this type to heat portions of the formation.
  • Material 494 may support insulated conductor 410 in conduit 382 .
  • the support provided by material 494 of insulated conductor 410 may allow for the deployment of long insulated conductors as compared to insulated conductors positioned only in a gas in a conduit without the use of special metallurgy to accommodate the weight of the insulated conductor.
  • insulated conductor 410 is buoyant in material 494 in conduit 382 .
  • insulated conductor may be buoyant in molten metal. The buoyancy of insulated conductor 410 reduces creep associated problems in long, substantially vertical heaters.
  • a bottom weight or tie down may be coupled to the bottom of insulated conductor 410 to inhibit the insulated conductor from floating in material 494 .
  • Material 494 may remain a liquid at operating temperatures of insulated conductor 410 .
  • material 494 melts at temperatures above about 100° C., above about 200° C., or above about 300° C.
  • the insulated conductor may operate at temperatures greater than 200° C., greater than 400° C., greater than 600° C., or greater than 800° C.
  • material 494 provides enhanced heat transfer from insulated conductor 410 to conduit 382 at or near the operating temperatures of the insulated conductor.
  • Material 494 may include metals such as tin, zinc, an alloy such as a 60% by weight tin, 40% by weight zinc alloy; bismuth; indium; cadmium, aluminum; lead; and/or combinations thereof (for example, eutectic alloys of these metals such as binary or ternary alloys).
  • material 494 is tin.
  • Some liquid metals may be corrosive.
  • the jacket of the insulated conductor and/or at least the inside surface of the canister may need to be made of a material that is resistant to the corrosion of the liquid metal.
  • the jacket of the insulated conductor and/or at least the inside surface of the conduit may be made of materials that inhibit the molten metal from leaching materials from the insulating conductor and/or the conduit to form eutectic compositions or metal alloys.
  • Molten metals may be highly thermal conductive, but may block radiant heat transfer from the insulated conductor and/or have relatively small heat transfer by natural convection.
  • Material 494 may be or include molten salts such as solar salt, salts presented in Table 1, or other salts.
  • the molten salts may be infrared transparent to aid in heat transfer from the insulated conductor to the canister.
  • solar salt includes sodium nitrate and potassium nitrate (for example, about 60% by weight sodium nitrate and about 40% by weight potassium nitrate).
  • Solar salt melts at about 220° C. and is chemically stable up to temperatures of about 593° C.
  • Other salts that may be used include, but are not limited to LiNO 3 (melt temperature (T m ) of 264° C.
  • eutectic mixtures such as 53% by weight KNO 3 , 40% by weight NaNO 3 and 7% by weight NaNO 2 (T m of about 142° C. and an upper working temperature of over 500° C.); 45.5% by weight KNO 3 and 54.5% by weight NaNO 2 (T m of about 142-145° C. and an upper working temperature of over 500° C.); or 50% by weight NaCl and 50% by weight SrCl 2 (T m of about 19° C. and an upper working temperature of over 1200° C.).
  • Some molten salts such as solar salt, may be relatively non-corrosive so that the conduit and/or the jacket may be made of relatively inexpensive material (for example, carbon steel). Some molten salts may have good thermal conductivity, may have high heat density, and may result in large heat transfer by natural convection.
  • the Rayleigh number is a dimensionless number associated with heat transfer in a fluid. When the Rayleigh number is below the critical value for the fluid, heat transfer is primarily in the form of conduction; and when the Rayleigh number is above the critical value, heat transfer is primarily in the form of convection.
  • the Rayleigh number is the product of the Grashof number (which describes the relationship between buoyancy and viscosity in a fluid) and the Prandtl number (which describes the relationship between momentum diffusivity and thermal diffusivity).
  • the Rayleigh number for solar salt in the conduit is about 10 times the Rayleigh number for tin in the conduit.
  • the higher Rayleigh number implies that the strength of natural convection in the molten solar salt is much stronger than the strength of the natural convection in molten tin.
  • the stronger natural convection of molten salt may distribute heat and inhibit the formation of hot spots at locations along the length of the conduit. Hot spots may be caused by coke build up at isolated locations adjacent to or on the conduit, contact of the conduit by the formation at isolated locations, and/or other high thermal load situations.
  • Conduit 382 may be a carbon steel or stainless steel canister.
  • conduit 382 may include cladding on the outer surface to inhibit corrosion of the conduit by formation fluid.
  • Conduit 382 may include cladding on an inner surface of the conduit that is corrosion resistant to material 494 in the conduit. Cladding applied to conduit 382 may be a coating and/or a liner. If the conduit contains a metal salt, the inner surface of the conduit may include coating of nickel, or the conduit may be or include a liner of a corrosion resistant metal such as Alloy N. If the conduit contains a molten metal, the conduit may include a corrosion resistant metal liner or coating, and/or a ceramic coating (for example, a porcelain coating or fired enamel coating).
  • conduit 382 is a canister of 410 stainless steel with an outside diameter of about 6 cm. Conduit 382 may not need a thick wall because material 494 may provide internal pressure that inhibits deformation or crushing of the conduit due to external stresses.
  • FIG. 64 depicts an embodiment of the heater positioned in wellbore 490 of formation 492 with a portion of insulated conductor 410 and conduit 382 oriented substantially horizontally in the formation.
  • Material 494 may provide a head in conduit 382 due to the pressure of the material.
  • the pressure head may keep material 494 in conduit 382 .
  • the pressure head may also provide internal pressure that inhibits deformation or collapse of conduit 382 due to external stresses.
  • two or more insulated conductors are placed in the conduit. In some embodiments, only one of the insulated conductors is energized. Should the energized conductor fail, one of the other conductors may be energized to maintain the material in a molten phase. The failed insulated conductor may be removed and/or replaced.
  • the conduit of the heater may be a ribbed conduit.
  • the ribbed conduit may improve the heat transfer characteristics of the conduit as compared to a cylindrical conduit.
  • FIG. 65 depicts a cross-sectional representation of ribbed conduit 496 .
  • FIG. 66 depicts a perspective view of a portion of ribbed conduit 496 .
  • Ribbed conduit 496 may include rings 498 and ribs 500 . Rings 498 and ribs 500 may improve the heat transfer characteristics of ribbed conduit 496 .
  • the cylinder of conduit has an inner diameter of about 5.1 cm and a wall thickness of about 0.57 cm. Rings 498 may be spaced about every 3.8 cm. Rings 498 may have a height of about 1.9 cm and a thickness of about 0.5 cm.
  • Ribs 500 may be spaced evenly about conduit 382 .
  • Ribs 500 may have a thickness of about 0.5 cm and a height of about 1.6 cm. Other dimensions for the cylinder, rings and ribs may be used.
  • Ribbed conduit 496 may be formed from two or more rolled pieces that are welded together to form the ribbed conduit. Other types of conduit with extra surface area to enhance heat transfer from the conduit to the formation may be used.
  • the ribbed conduit may be used as the conduit of a conductor-in-conduit heater.
  • the conductor may be a 3.05 cm 410 stainless steel rod and the conduit has dimensions as described above.
  • the conductor is an insulated conductor and a fluid is positioned between the conductor and the ribbed conduit.
  • the fluid may be a gas or liquid at operating temperatures of the insulated conductor.
  • the heat source for the heater is not an insulated conductor.
  • the heat source may be hot fluid circulated through an inner conduit positioned in an outer conduit.
  • the material may be positioned between the inner conduit and the outer conduit. Convection currents in the material may help to more evenly distribute heat to the formation and may inhibit or limit formation of a hot spot where insulation that limits heat transfer to the overburden ends.
  • the heat sources are downhole oxidizers.
  • the material is placed between an outer conduit and an oxidizer conduit.
  • the oxidizer conduit may be an exhaust conduit for the oxidizers or the oxidant conduit if the oxidizers are positioned in a u-shaped wellbore with exhaust gases exiting the formation through one of the legs of the u-shaped conduit. The material may help inhibit the formation of hot spots adjacent to the oxidizers of the oxidizer assembly.
  • the material to be heated by the insulated conductor may be placed in an open wellbore.
  • FIG. 67 depicts material 494 in open wellbore 490 in formation 492 with insulated conductor 410 in the wellbore.
  • a gas for example, nitrogen, carbon dioxide, and/or helium
  • the gas may inhibit oxidation or other chemical changes of material 494 .
  • the gas may inhibit vaporization of material 494 .
  • Material 494 may have a melting point that is above the pyrolysis temperature of hydrocarbons in the formation.
  • the melting point of material 494 may be above 375° C., above 400° C., or above 425° C.
  • the insulated conductor may be energized to heat the formation. Heat from the insulated conductor may pyrolyze hydrocarbons in the formation. Adjacent the wellbore, the heat from insulated conductor 410 may result in coking that reduces the permeability and plugs the formation near wellbore 490 .
  • the plugged formation inhibits material 494 from leaking from wellbore 490 into formation 492 when the material is a liquid.
  • material 494 is a salt.
  • material 494 leaking from wellbore 490 into formation 492 may be self-healing and/or self-sealing.
  • Material 494 flowing away from wellbore 490 may travel until the temperature becomes less than the solidification temperature of the material. Temperature may drop rapidly a relatively small distance away from the heater used to maintain material 494 in a liquid state. The rapid drop off in temperature may result in migrating material 494 solidifying close to wellbore 490 . Solidified material 494 may inhibit migration of additional material from wellbore 490 , and thus self-heal and/or self-seal the wellbore.
  • Return electrical current for insulated conductor 410 may return through jacket 370 of the insulated conductor. Any current that passes through material 494 may pass to ground. Above the level of material 494 , any remaining return electrical current may be confined to jacket 370 of insulated conductor 410 .
  • Using liquid material in open wellbores heated by heaters may allow for delivery of high power rates (for example, up to about 2000 W/m) to the formation with relatively low heater surface temperatures.
  • Hot spot generation in the formation may be reduced or eliminated due to convection smoothing out the temperature profile along the length of the heater.
  • Natural convection occurring in the wellbore may greatly enhance heat transfer from the heater to the formation.
  • the large gap between the formation and the heater may prevent thermal expansion of the formation from harming the heater.
  • an 8′′ (20.3 cm) wellbore may be formed in the formation.
  • casing may be placed through all or a portion of the overburden.
  • a 0.6 inch (1.5 cm) diameter insulated conductor heater may be placed in the wellbore.
  • the wellbore may be filled with solid material (for example, solid particles of salt).
  • a packer may be placed near an interface between the treatment area and the overburden.
  • a pass through conduit in the packer may be included to allow for the addition of more material to the treatment area.
  • a non-reactive or substantially non-reactive gas (for example, carbon dioxide and/or nitrogen) may be introduced into the wellbore.
  • the insulated conductor may be energized to begin the heating that melts the solid material and heats the treatment area.
  • other types of heat sources besides for insulated conductors are used to heat the material placed in the open wellbore.
  • the other types of heat sources may include gas burners, pipes through which hot heat transfer fluid flows, or other types of heaters.
  • heat pipes are placed in the formation.
  • the heat pipes may reduce the number of active heat sources needed to heat a treatment area of a given size.
  • the heat pipes may reduce the time needed to heat the treatment area of a given size to a desired average temperature.
  • a heat pipe is a closed system that utilizes phase change of fluid in the heat pipe to transport heat applied to a first region to a second region remote from the first region. The phase change of the fluid allows for large heat transfer rates.
  • Heat may be applied to the first region of the heat pipes from any type of heat source, including but not limited to, electric heaters, oxidizers, heat provided from geothermal sources, and/or heat provided from nuclear reactors.
  • Heat pipes are passive heat transport systems that include no moving parts. Heat pipes may be positioned in near horizontal to vertical configurations.
  • the fluid used in heat pipes for heating the formation may have a low cost, a low melting temperature, a boiling temperature that is not too high (for example, generally below about 900° C.), a low viscosity at temperatures below about 540° C., a high heat of vaporization, and a low corrosion rate for the heat pipe material.
  • the heat pipe includes a liner of material that is resistant to corrosion by the fluid. TABLE 1 shows melting and boiling temperatures for several materials that may be used as the fluid in heat pipes.
  • salts that may be used include, but are not limited to LiNO 3 , and eutectic mixtures such as 53% by weight KNO 3 ; 40% by weight NaNO 3 and 7% by weight NaNO 2 ; 45.5% by weight KNO 3 and 54.5% by weight NaNO 2 ; or 50% by weight NaCl and 50% by weight SrCl 2 .
  • FIG. 68 depicts schematic cross-sectional representation of a portion of a formation with heat pipes 502 positioned adjacent to a substantially horizontal portion of heat source 202 .
  • Heat source 202 is placed in a wellbore in the formation.
  • Heat source 202 may be a gas burner assembly, an electrical heater, a leg of a circulation system that circulates hot fluid through the formation, or other type of heat source.
  • Heat pipes 502 may be placed in the formation so that distal ends of the heat pipes are near or contact heat source 202 .
  • heat pipes 502 mechanically attach to heat source 202 .
  • Heat pipes 502 may be spaced a desired distance apart. In an embodiment, heat pipes 502 are spaced apart by about 40 feet. In other embodiments, large or smaller spacings are used.
  • Heat pipes 502 may be placed in a regular pattern with each heat pipe spaced a given distance from the next heat pipe. In some embodiments, heat pipes 502 are placed in an irregular pattern. An irregular pattern may be used to provide a greater amount of heat to a selected portion or portions of the formation. Heat pipes 502 may be vertically positioned in the formation. In some embodiments, heat pipes 502 are placed at an angle in the formation.
  • Heat pipes 502 may include sealed conduit 504 , seal 506 , liquid heat transfer fluid 508 and vaporized heat transfer fluid 510 .
  • heat pipes 502 include metal mesh or wicking material that increases the surface area for condensation and/or promotes flow of the heat transfer fluid in the heat pipe.
  • Conduit 504 may have first portion 512 and second portion 514 .
  • Liquid heat transfer fluid 508 may be in first portion 512 .
  • Heat source 202 external to heat pipe 502 supplies heat that vaporizes liquid heat transfer fluid 508 .
  • Vaporized heat transfer fluid 510 diffuses into second portion 514 . Vaporized heat transfer fluid 510 condenses in second portion and transfers heat to conduit 504 , which in turn transfers heat to the formation.
  • the condensed liquid heat transfer fluid 508 flows by gravity to first portion 512 .
  • Position of seal 506 is a factor in determining the effective length of heat pipe 502 .
  • the effective length of heat pipe 502 may also depend on the physical properties of the heat transfer fluid and the cross-sectional area of conduit 504 . Enough heat transfer fluid may be placed in conduit 504 so that some liquid heat transfer fluid 508 is present in first portion 512 at all times.
  • Seal 506 may provide a top seal for conduit 504 .
  • conduit 504 is purged with nitrogen, helium or other fluid prior to being loaded with heat transfer fluid and sealed.
  • a vacuum may be drawn on conduit 504 to evacuate the conduit before the conduit is sealed. Drawing a vacuum on conduit 504 before sealing the conduit may enhance vapor diffusion throughout the conduit.
  • an oxygen getter may be introduced in conduit 504 to react with any oxygen present in the conduit.
  • FIG. 69 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with heat pipe 502 located radially around oxidizer assembly 516 .
  • Oxidizers 518 of oxidizer assembly 516 are positioned adjacent to first portion 512 of heat pipe 502 .
  • Fuel may be supplied to oxidizers 518 through fuel conduit 520 .
  • Oxidant may be supplied to oxidizers 518 through oxidant conduit 522 .
  • Exhaust gas may flow through the space between outer conduit 524 and oxidant conduit 522 .
  • Oxidizers 518 combust fuel to provide heat that vaporizes liquid heat transfer fluid 508 .
  • Vaporized heat transfer fluid 510 rises in heat pipe 502 and condenses on walls of the heat pipe to transfer heat to sealed conduit 504 .
  • Exhaust gas from oxidizers 518 provides heat along the length of sealed conduit 504 .
  • the heat provided by the exhaust gas along the effective length of heat pipe 502 may increase convective heat transfer and/or reduce the lag time before significant heat is provided to the formation from the heat pipe along the effective length of the heat pipe.
  • FIG. 70 depicts a cross-sectional representation of an angled heat pipe embodiment with oxidizer assembly 516 located near a lowermost portion of heat pipe 502 .
  • Fuel may be supplied to oxidizers 518 through fuel conduit 520 .
  • Oxidant may be supplied to oxidizers 518 through oxidant conduit 522 .
  • Exhaust gas may flow through the space between outer conduit 524 and oxidant conduit 522 .
  • FIG. 71 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with oxidizer 518 located at the bottom of heat pipe 502 .
  • Fuel may be supplied to oxidizer 518 through fuel conduit 520 .
  • Oxidant may be supplied to oxidizer 518 through oxidant conduit 522 .
  • Exhaust gas may flow through the space between the outer wall of heat pipe 502 and outer conduit 524 .
  • Oxidizer 518 combusts fuel to provide heat that vaporizers liquid heat transfer fluid 508 .
  • Vaporized heat transfer fluid 510 rises in heat pipe 502 and condenses on walls of the heat pipe to transfer heat to sealed conduit 504 .
  • Exhaust gas from oxidizers 518 provides heat along the length of sealed conduit 504 and to outer conduit 524 .
  • the heat provided by the exhaust gas along the effective length of heat pipe 502 may increase convective heat transfer and/or reduce the lag time before significant heat is provided to the formation from the heat pipe and oxidizer combination along the effective length of the heat pipe.
  • FIG. 72 depicts a similar embodiment with heat pipe 502 positioned at an angle in the formation.
  • FIG. 73 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with oxidizer 518 that produces flame zone adjacent to liquid heat transfer fluid 508 in the bottom of heat pipe 502 .
  • Fuel may be supplied to oxidizer 518 through fuel conduit 520 .
  • Oxidant may be supplied to oxidizer 518 through oxidant conduit 522 .
  • Oxidant and fuel are mixed and combusted to produce flame zone 526 .
  • Flame zone 526 provides heat that vaporizes liquid heat transfer fluid 508 .
  • Exhaust gases from oxidizer 518 may flow through the space between oxidant conduit 522 and the inner surface of heat pipe 502 , and through the space between the outer surface of the heat pipe and outer conduit 524 .
  • the heat provided by the exhaust gas along the effective length of heat pipe 502 may increase convective heat transfer and/or reduce the lag time before significant heat is provided to the formation from the heat pipe and oxidizer combination along the effective length of the heat pipe.
  • FIG. 74 depicts a perspective cut-out representation of a portion of a heat pipe embodiment with a tapered bottom that accommodates multiple oxidizers of an oxidizer assembly.
  • efficient heat pipe operation requires a high heat input.
  • Multiple oxidizers of oxidizer assembly 516 may provide high heat input to liquid heat transfer fluid 508 of heat pipe 502 .
  • a portion of oxidizer assembly with the oxidizers may be helically wound around a tapered portion of heat pipe 502 .
  • the tapered portion may have a large surface area to accommodate the oxidizers.
  • Fuel may be supplied to the oxidizers of oxidizer assembly 516 through fuel conduit 520 .
  • Oxidant may be supplied to oxidizer 518 through oxidant conduit 522 .
  • Exhaust gas may flow through the space between the outer wall of heat pipe 502 and outer conduit 524 .
  • Exhaust gas from oxidizers 518 provides heat along the length of sealed conduit 504 and to outer conduit 524 .
  • the heat provided by the exhaust gas along the effective length of heat pipe 502 may increase convective heat transfer and/or reduce the lag time before significant heat is provided to the formation from the heat pipe and oxidizer combination along the effective length of the heat pipe.
  • FIG. 75 depicts a cross-sectional representation of a heat pipe embodiment that is angled within the formation.
  • First wellbore 528 and second wellbore 530 are drilled in the formation using magnetic ranging or techniques so that the first wellbore intersects the second wellbore.
  • Heat pipe 502 may be positioned in first wellbore 528 .
  • First wellbore 528 may be sloped so that liquid heat transfer fluid 508 within heat pipe 502 is positioned near the intersection of the first wellbore and second wellbore 530 .
  • Oxidizer assembly 516 may be positioned in second wellbore 530 .
  • Oxidizer assembly 516 provides heat to heat pipe 502 that vaporizes liquid heat transfer fluid in the heat pipe.
  • Packer or seal 532 may direct exhaust gas from oxidizer assembly 516 through first wellbore 528 to provide additional heat to the formation from the exhaust gas.
  • the temperature limited heater is used to achieve lower temperature heating (for example, for heating fluids in a production well, heating a surface pipeline, or reducing the viscosity of fluids in a wellbore or near wellbore region). Varying the ferromagnetic materials of the temperature limited heater allows for lower temperature heating.
  • the ferromagnetic conductor is made of material with a lower Curie temperature than that of 446 stainless steel.
  • the ferromagnetic conductor may be an alloy of iron and nickel. The alloy may have between 30% by weight and 42% by weight nickel with the rest being iron.
  • the alloy is Invar 36. Invar 36 is 36% by weight nickel in iron and has a Curie temperature of 277° C.
  • an alloy is a three component alloy with, for example, chromium, nickel, and iron.
  • an alloy may have 6% by weight chromium, 42% by weight nickel, and 52% by weight iron.
  • a 2.5 cm diameter rod of Invar 36 has a turndown ratio of approximately 2 to 1 at the Curie temperature. Placing the Invar 36 alloy over a copper core may allow for a smaller rod diameter. A copper core may result in a high turndown ratio.
  • the insulator in lower temperature heater embodiments may be made of a high performance polymer insulator (such as PFA or PEEKTM) when used with alloys with a Curie temperature that is below the melting point or softening point of the polymer insulator.
  • a conductor-in-conduit temperature limited heater is used in lower temperature applications by using lower Curie temperature and/or the phase transformation temperature range ferromagnetic materials.
  • a lower Curie temperature and/or the phase transformation temperature range ferromagnetic material may be used for heating inside sucker pump rods.
  • Heating sucker pump rods may be useful to lower the viscosity of fluids in the sucker pump or rod and/or to maintain a lower viscosity of fluids in the sucker pump rod. Lowering the viscosity of the oil may inhibit sticking of a pump used to pump the fluids.
  • Fluids in the sucker pump rod may be heated up to temperatures less than about 250° C. or less than about 300° C. Temperatures need to be maintained below these values to inhibit coking of hydrocarbon fluids in the sucker pump system.
  • a temperature limited heater includes a flexible cable (for example, a furnace cable) as the inner conductor.
  • the inner conductor may be a 27% nickel-clad or stainless steel-clad stranded copper wire with four layers of mica tape surrounded by a layer of ceramic and/or mineral fiber (for example, alumina fiber, aluminosilicate fiber, borosilicate fiber, or aluminoborosilicate fiber).
  • a stainless steel-clad stranded copper wire furnace cable may be available from Anomet Products, Inc.
  • the inner conductor may be rated for applications at temperatures of 1000° C. or higher.
  • the inner conductor may be pulled inside a conduit.
  • the conduit may be a ferromagnetic conduit (for example, a 3 ⁇ 4′′ Schedule 80 446 stainless steel pipe).
  • the conduit may be covered with a layer of copper, or other electrical conductor, with a thickness of about 0.3 cm or any other suitable thickness.
  • the assembly may be placed inside a support conduit (for example, a 11 ⁇ 4′′ Schedule 80 347H or 347HH stainless steel tubular).
  • the support conduit may provide additional creep-rupture strength and protection for the copper and the inner conductor.
  • the inner copper conductor may be plated with a more corrosion resistant alloy (for example, Incoloy® 825) to inhibit oxidation.
  • the top of the temperature limited heater is sealed to inhibit air from contacting the inner conductor.
  • FIG. 76 depicts an embodiment of three heaters coupled in a three-phase configuration.
  • Conductor “legs” 534 , 536 , 538 are coupled to three-phase transformer 414 .
  • Transformer 414 may be an isolated three-phase transformer. In certain embodiments, transformer 414 provides three-phase output in a wye configuration. Input to transformer 414 may be made in any input configuration, such as the shown delta configuration.
  • Legs 534 , 536 , 538 each include lead-in conductors 540 in the overburden of the formation coupled to heating elements 542 in hydrocarbon layer 388 .
  • Lead-in conductors 540 include copper with an insulation layer.
  • lead-in conductors 540 may be a 4-0 copper cables with TEFLON® insulation, a copper rod with polyurethane insulation, or other metal conductors such as bare copper or aluminum.
  • lead-in conductors 540 are located in an overburden portion of the formation.
  • the overburden portion may include overburden casings 398 .
  • Heating elements 542 may be temperature limited heater heating elements.
  • heating elements 542 are 410 stainless steel rods (for example, 3.1 cm diameter 410 stainless steel rods).
  • heating elements 542 are composite temperature limited heater heating elements (for example, 347 stainless steel, 410 stainless steel, copper composite heating elements; 347 stainless steel, iron, copper composite heating elements; or 410 stainless steel and copper composite heating elements). In certain embodiments, heating elements 542 have a length of about 10 m to about 2000 m, about 20 m to about 400 m, or about 30 m to about 300 m.
  • heating elements 542 are exposed to hydrocarbon layer 388 and fluids from the hydrocarbon layer. Thus, heating elements 542 are “bare metal” or “exposed metal” heating elements. Heating elements 542 may be made from a material that has an acceptable sulfidation rate at high temperatures used for pyrolyzing hydrocarbons. In certain embodiments, heating elements 542 are made from material that has a sulfidation rate that decreases with increasing temperature over at least a certain temperature range (for example, 500° C. to 650° C., 530° C. to 650° C., or 550° C. to 650° C.).
  • heating elements 542 are made from material that has a sulfidation rate below a selected value in a temperature range. In some embodiments, heating elements 542 are made from material that has a sulfidation rate at most about 25 mils per year at a temperature between about 800° C. and about 880° C. In some embodiments, the sulfidation rate is at most about 35 mils per year at a temperature between about 800° C.
  • Heating elements 542 may also be substantially inert to galvanic corrosion.
  • heating elements 542 have a thin electrically insulating layer such as aluminum oxide or thermal spray coated aluminum oxide.
  • the thin electrically insulating layer is a ceramic composition such as an enamel coating.
  • Enamel coatings include, but are not limited to, high temperature porcelain enamels.
  • High temperature porcelain enamels may include silicon dioxide, boron oxide, alumina, and alkaline earth oxides (CaO or MgO), and minor amounts of alkali oxides (Na 2 O, K 2 O, LiO).
  • the enamel coating may be applied as a finely ground slurry by dipping the heating element into the slurry or spray coating the heating element with the slurry.
  • the coated heating element is then heated in a furnace until the glass transition temperature is reached so that the slurry spreads over the surface of the heating element and makes the porcelain enamel coating.
  • the porcelain enamel coating contracts when cooled below the glass transition temperature so that the coating is in compression.
  • the thin electrically insulating layer has low thermal impedance allowing heat transfer from the heating element to the formation while inhibiting current leakage between heating elements in adjacent openings and/or current leakage into the formation.
  • the thin electrically insulating layer is stable at temperatures above at least 350° C., above 500° C., or above 800° C.
  • the thin electrically insulating layer has an emissivity of at least 0.7, at least 0.8, or at least 0.9. Using the thin electrically insulating layer may allow for long heater lengths in the formation with low current leakage.
  • Heating elements 542 may be coupled to contacting elements 544 at or near the underburden of the formation.
  • Contacting elements 544 are copper or aluminum rods or other highly conductive materials.
  • transition sections 546 are located between lead-in conductors 540 and heating elements 542 , and/or between heating elements 542 and contacting elements 544 .
  • Transition sections 546 may be made of a conductive material that is corrosion resistant such as 347 stainless steel over a copper core.
  • transition sections 546 are made of materials that electrically couple lead-in conductors 540 and heating elements 542 while providing little or no heat output.
  • transition sections 546 help to inhibit overheating of conductors and insulation used in lead-in conductors 540 by spacing the lead-in conductors from heating elements 542 .
  • Transition section 546 may have a length of between about 3 m and about 9 m (for example, about 6 m).
  • Contacting elements 544 are coupled to contactor 548 in contacting section 550 to electrically couple legs 534 , 536 , 538 to each other.
  • contact solution 552 for example, conductive cement
  • legs 534 , 536 , 538 are substantially parallel in hydrocarbon layer 388 and leg 534 continues substantially vertically into contacting section 550 .
  • the other two legs 536 , 538 are directed (for example, by directionally drilling the wellbores for the legs) to intercept leg 534 in contacting section 550 .
  • Each leg 534 , 536 , 538 may be one leg of a three-phase heater embodiment so that the legs are substantially electrically isolated from other heaters in the formation and are substantially electrically isolated from the formation.
  • Legs 534 , 536 , 538 may be arranged in a triangular pattern so that the three legs form a triangular shaped three-phase heater.
  • legs 534 , 536 , 538 are arranged in a triangular pattern with 12 m spacing between the legs (each side of the triangle has a length of 12 m).
  • FIG. 77 depicts a side view representation of an embodiment of a substantially u-shaped three-phase heater.
  • First ends of legs 534 , 536 , 538 are coupled to transformer 414 at first location 554 .
  • transformer 414 is a three-phase AC transformer.
  • Ends of legs 534 , 536 , 538 are electrically coupled together with connector 556 at second location 558 .
  • Connector 556 electrically couples the ends of legs 534 , 536 , 538 so that the legs can be operated in a three-phase configuration.
  • legs 534 , 536 , 538 are coupled to operate in a three-phase wye configuration.
  • legs 534 , 536 , 538 are substantially parallel in hydrocarbon layer 388 . In certain embodiments, legs 534 , 536 , 538 are arranged in a triangular pattern in hydrocarbon layer 388 .
  • heating elements 542 include thin electrically insulating material (such as a porcelain enamel coating) to inhibit current leakage from the heating elements. In certain embodiments, the thin electrically insulating layer allows for relatively long, substantially horizontal heater leg lengths in the hydrocarbon layer with a substantially u-shaped heater. In certain embodiments, legs 534 , 536 , 538 are electrically coupled so that the legs are substantially electrically isolated from other heaters in the formation and are substantially electrically isolated from the formation.
  • overburden casings in overburden 400 include materials that inhibit ferromagnetic effects in the casings. Inhibiting ferromagnetic effects in casings 398 reduces heat losses to the overburden.
  • casings 398 may include non-metallic materials such as fiberglass, polyvinylchloride (PVC), chlorinated polyvinylchloride (CPVC), or high-density polyethylene (HDPE).
  • HDPEs with working temperatures in a range for use in overburden 400 include HDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.).
  • casings 398 include carbon steel coupled on the inside diameter of a non-ferromagnetic metal (for example, carbon steel clad with copper or aluminum) to inhibit ferromagnetic effects or inductive effects in the carbon steel.
  • a non-ferromagnetic metal for example, carbon steel clad with copper or aluminum
  • Other non-ferromagnetic metals include, but are not limited to, manganese steels with at least 10% by weight manganese, iron aluminum alloys with at least 18% by weight aluminum, and austentitic stainless steels such as 304 stainless steel or 316 stainless steel.
  • one or more non-ferromagnetic materials used in casings 398 are used in a wellhead coupled to the casings and legs 534 , 536 , 538 . Using non-ferromagnetic materials in the wellhead inhibits undesirable heating of components in the wellhead.
  • a purge gas for example, carbon dioxide, nitrogen or argon
  • one or more of legs 534 , 536 , 538 are installed in the formation using coiled tubing.
  • coiled tubing is installed in the formation, the leg is installed inside the coiled tubing, and the coiled tubing is pulled out of the formation to leave the leg installed in the formation.
  • the leg may be placed concentrically inside the coiled tubing.
  • coiled tubing with the leg inside the coiled tubing is installed in the formation and the coiled tubing is removed from the formation to leave the leg installed in the formation.
  • the coiled tubing may extend only to a junction of the hydrocarbon layer and the contacting section, or to a point at which the leg begins to bend in the contacting section.
  • FIG. 78 depicts a top view representation of an embodiment of a plurality of triads of three-phase heaters in the formation.
  • Each triad 560 includes legs A, B, C (which may correspond to legs 534 , 536 , 538 depicted in FIGS. 76 and 77 ) that are electrically coupled by linkages 562 .
  • Each triad 560 is coupled to its own electrically isolated three-phase transformer so that the triads are substantially electrically isolated from each other. Electrically isolating the triads inhibits net current flow between triads.
  • each triad 560 may be arranged so that legs A, B, C correspond between triads as shown in FIG. 78 .
  • Legs A, B, C are arranged such that a phase leg (for example, leg A) in a given triad is about two triad heights from a same phase leg (leg A) in an adjacent triad.
  • the triad height is the distance from a vertex of the triad to a midpoint of the line intersecting the other two vertices of the triad.
  • the phases of triads 560 are arranged to inhibit net current flow between individual triads. There may be some leakage of current within an individual triad but little net current flows between two triads due to the substantial electrical isolation of the triads and, in certain embodiments, the arrangement of the triad phases.
  • an exposed heating element may leak some current to water or other fluids that are electrically conductive in the formation so that the formation itself is heated.
  • the heating elements After water or other electrically conductive fluids are removed from the wellbore (for example, vaporized or produced), the heating elements become electrically isolated from the formation. Later, when water is removed from the formation, the formation becomes even more electrically resistant and heating of the formation occurs even more predominantly via thermally conductive and/or radiative heating.
  • the formation (the hydrocarbon layer) has an initial electrical resistance that averages at least 10 ohm ⁇ m. In some embodiments, the formation has an initial electrical resistance of at least 100 ohm ⁇ m or of at least 300 ohm ⁇ m.
  • temperature limited heaters limits the effect of water saturation on heater efficiency. With water in the formation and in heater wellbores, there is a tendency for electrical current to flow between heater elements at the top of the hydrocarbon layer where the voltage is highest and cause uneven heating in the hydrocarbon layer. This effect is inhibited with temperature limited heaters because the temperature limited heaters reduce localized overheating in the heating elements and in the hydrocarbon layer.
  • production wells are placed at a location at which there is relatively little or zero voltage potential. This location minimizes stray potentials at the production well. Placing production wells at such locations improves the safety of the system and reduces or inhibits undesired heating of the production wells caused by electrical current flow in the production wells.
  • FIG. 79 depicts a top view representation of the embodiment depicted in FIG. 78 with production wells 206 . In certain embodiments, production wells 206 are located at or near center of triad 560 .
  • production wells 206 are placed at a location between triads at which there is relatively little or zero voltage potential (at a location at which voltage potentials from vertices of three triads average out to relatively little or zero voltage potential).
  • production well 206 may be at a location equidistant from leg A of one triad, leg B of a second triad, and leg C of a third triad, as shown in FIG. 79 .
  • Certain embodiments of heaters include single-phase conductors in a single wellbore.
  • FIGS. 76 and 77 depict heater embodiments with three-phase heaters that include single-phase conductors in each wellbore.
  • a problem with having a single-phase conductor in the wellbore is current or voltage induction in components of the wellbore (for example, the heater casing) and/or in the formation caused by magnetic fields produced by the single-phase conductor.
  • the magnetic fields produced by the current running through the supply conductor are cancelled by magnetic fields produced by the current running through the return conductor.
  • the single-phase conductor may induce currents in production wellbores and/or other nearby wellbores.
  • FIG. 80 depicts a schematic of an embodiment of a heat treatment system including heater 412 and production wells 206 .
  • heater 412 is a three-phase heater that includes legs 534 , 536 , 538 coupled to transformer 414 and terminal connector 556 .
  • Legs 534 , 536 , 538 may each include single-phase conductors.
  • Legs 534 , 536 , 538 may be coupled together to form a triad heater.
  • legs 534 , 536 , 538 are relatively long heater sections. For example, legs 534 , 536 , 538 may be about 3000 m or longer in length.
  • production wells 206 are located substantially horizontally in the formation and below legs 534 , 536 , 538 of heater 412 . In some embodiments, production wells 206 are located at an incline or vertically in the formation. As shown in FIG. 80 , production wells 206 may include two production wells that extend from each side of heater 412 towards the center of the heater substantially lengthwise along the heated sections of legs 534 , 536 , 538 . In some embodiments, one production well 206 extends substantially lengthwise along the heated sections of the legs.
  • FIG. 81 depicts a side-view representation of one leg of heater 412 in the subsurface formation.
  • Leg 534 is shown as representative of any leg in of heater 412 in the formation.
  • Leg 534 may include heating element 542 in hydrocarbon layer 388 below overburden 400 .
  • heating element 542 is located substantially horizontal in hydrocarbon layer 388 .
  • Transition section 546 may couple heating element 542 to lead-in cable 540 .
  • Lead-in cable 540 may be an overburden section or overburden element of heater 412 .
  • Lead-in cable 540 couples heating element 542 and transition section 546 to electrical components at the surface (for example, transformer 414 and/or terminal connector 556 depicted in FIG. 80 ).
  • heater casing 564 extends from the surface to at or near end of transition section 546 .
  • Overburden casing 398 substantially surrounds heater casing 564 in overburden 400 .
  • Surface conductor 566 substantially surrounds overburden casing 398 at or near the surface of the formation.
  • heating element 542 is an exposed metal or bare metal heating element.
  • heating element 542 may be an exposed ferromagnetic metal heating element such as 410 stainless steel.
  • Lead-in cable 540 includes low resistance electrical conductors such as copper or copper-cladded steel.
  • Lead-in cable 540 may include electrical insulation or otherwise be electrically insulated from overburden 400 (for example, overburden casing 398 may include electrical insulation on an inside surface of the casing).
  • Transition section 546 may include a combination of stainless steel and copper suitable for transition between heating element 542 and lead-in cable 540 .
  • heater casing 564 includes non-ferromagnetic stainless steel or another suitable material that has high hanging strength and is non-ferromagnetic.
  • Overburden casing 398 and/or surface conductor 566 may include carbon steel or other suitable materials.
  • FIG. 82 depicts a schematic representation of a surface cabling configuration with a ground loop used for heater 412 and production well 206 .
  • ground loop 568 substantially surrounds legs 534 , 536 , 538 of heater 412 , production well 206 , and transformer 414 .
  • Power cable 394 may couple transformer 414 to legs 534 , 536 , 538 of heater 412 .
  • the center portion of power cable 394 coupled to center leg 536 may be put into loop 570 .
  • Loop 570 extends the center portion of power cable 394 to have approximately the same length as the portions of power cable 394 coupled to side legs 534 , 538 . Having each portion of power cable 394 approximately the same length inhibits creation of phase differences between the legs.
  • transformer 414 is coupled to ground loop 568 to ground the transformer and heater 412 .
  • production well 206 is coupled to ground loop 568 to ground the production well.
  • FIG. 83 depicts a side view of an overburden portion of leg 534 .
  • Lead-in cable 540 is substantially surrounded by heater casing 564 and overburden casing 398 (“casing 564 / 398 ”) in the overburden of the formation.
  • Current flow in lead-in cable 540 (represented by +/ ⁇ symbols at ends the lead-in cable) induces current flow with opposite polarity on casing 564 / 398 (represented by +/ ⁇ symbols on line 572 ).
  • This induced voltage on casing 564 / 398 is caused by mutual inductance of the casing with all the heater elements in the triad (each of the three-phase elements in the formation).
  • the mutual inductance may be described by the following equation:
  • the induced voltages and currents on casing 564 / 398 can be relatively high. Large induced currents on the casing may lead to AC corrosion problems and/or leakage of current into the formation. Large currents on the casing, when grounded, may also necessitate large currents in the ground loop to compensate for the currents on the casing. Large currents on the ground loop may be costly and, in some cases, be difficult or unsafe to operate. Large currents on the casing may also lead to high surface potentials around the heaters on the surface. High surface potentials may create unsafe areas for personnel and/or equipment on the surface.
  • Simulations may be used to assess and/or determine the location and magnitude of induced casing and ground currents in the formation.
  • simulation systems available from Safe Engineering Services & Technologies, Ltd. (Laval, Quebec, Canada) may be used to assess induced casing and ground currents for subsurface heating systems.
  • Data such as, but not limited to, physical dimensions of the heaters, electrical and magnetic properties of materials used, formation resistivity profile, and applied voltage/current including phase profile may be used in the simulation to assess induced casing and ground currents.
  • FIG. 84 depicts a side view of overburden portions of legs 534 , 536 grounded to ground loop 568 .
  • Legs 534 , 536 have opposite polarity such that the currents induced in the casings of the legs also have opposite polarity.
  • the opposite polarity of the casings causes circular current flow between the legs through the overburden. This circular current flow is represented by curve 574 .
  • curve 574 the magnitude of circular current flow (curve 574 ) (current density on the casings) is relatively large. For example, current densities in the heater casing may be 1 A/m 2 or greater. Such current densities may increase the risk of AC corrosion in the heater casing.
  • FIG. 85 depicts a side view of overburden portions of legs 534 , 536 with the legs grounded to a ground loop.
  • Ungrounding legs 534 , 536 reduces the magnitude of the circular current flow between the legs (current density on the casings), as shown by curve 574 .
  • the current density on the heater casing may be lowered by a factor of about 2. This reduction in magnitude may, however, not be large enough to satisfy regulatory and/or safety issues with the induced current as the induced current remains near the surface of the formation.
  • additional regulatory and/or safety issues associated with ungrounding legs 534 , 536 such as, but not limited to, increasing wellhead electrical fields above safe levels.
  • FIG. 86 depicts a side view of overburden portions of legs 534 , 536 with the electrically conductive portions of casings 564 / 398 lowered selected depth 576 below the surface.
  • lowering the conductive portion of casings 564 / 398 selected depth 576 reduces the magnitude of the induced current (current density on the casings) and moves the induced current to the selected depth below the surface. Moving the induced current to selected depth 576 below the surface reduces surface potentials and ground currents from the induced currents in the casings.
  • the current density on the heater casing may be lowered by a factor of about 3 by lowering the conductive portion of the casing.
  • the conductive portions of casings 564 / 398 are lowered in the formation by using electrically non-conductive materials in the portions of the casings above the conductive portions of the casings.
  • casings 564 / 398 may include non-conductive portions between the surface and the selected depth and conductive portions below the selected depth.
  • the electrically non-conductive portions include materials such as, but not limited to, fiberglass or other electrically insulating materials.
  • the non-conductive portion of casing 564 / 398 may only be used to the selected depth because the use of the non-conductive material may not be feasible.
  • the non-conductive material may have low temperature limits that inhibits use of the non-conductive material near the heated section of the heater. Thus, conductive material may need to be used in the lower part of the overburden portion of the heater (the part near the heated section).
  • the non-conductive material may not be high strength material, to support the weight of the conductive material (for example, stainless steel), the conductive portion may be located as close to the surface as possible. Locating the conductive portion closer to the surface reduces the size of hanging devices or other structures that may be used to support the conductive portion of the casing.
  • the non-conductive portion of casing 564 / 398 extends to a depth that is below the surface moisture zone in the formation. Keeping the conductive portion of casing 564 / 398 below the surface moisture zone inhibits induced currents from reaching the surface.
  • the non-conductive portion of casing 564 / 398 extends to a depth that is at least the distance between legs 534 , 536 .
  • the non-conductive portion of casing 564 / 398 may extend at least about 100′ (about 30 m) below the surface.
  • the non-conductive portion of casing 564 / 398 extends at least about 15 m, at least about 20 m, or at least about 30 m below the surface.
  • the non-conductive portion of casing 564 / 398 may extend to a depth of at most about 150 m, about 300 m, or about 500 m from the surface.
  • the non-conductive portion of casing 564 / 398 may extend at most to a selected distance from the heated zone of the formation (the heated portion of the heater). In some embodiments, the selected distance is about 100 m, about 150 m, or about 200 m. In some embodiments, the non-conductive portion of casing 564 / 398 may extend to a depth that is slightly above or near the beginning of the bend in a u-shaped heater.
  • the desired depth of non-conductive portion of casing 564 / 398 may be assessed based on electrical effects for the formation to be treated and/or electrical properties of the heaters to be used. Simulations, such as those available from Safe Engineering Services & Technologies, Ltd. (Laval, Quebec, Canada), may be used to assess the desired depth of the non-conductive portion of the casing. The desired depth may also be affected by factors such as, but not limited to, safety issues, regulatory issues, and mechanical issues.
  • the overburden portions of legs 534 , 536 are moved closer together so that the non-conductive portion of casing 564 / 398 can be moved to a shallower depth.
  • the overburden portions of legs 534 , 536 may be relatively close together while the heated portions of the legs diverge below the overburden to greater separation distances needed for desired heating the formation.
  • legs 534 , 536 are ungrounded with the casings lowered the selected distance. In some embodiments, however, legs 534 , 536 are grounded with the casings lowered the selected distance. The grounding or ungrounding of the legs may affect the selected depth to which the casings are lowered.
  • ground loop 568 may become the highest field gradient at the surface.
  • a ground wellbore may be located below the surface and coupled to ground loop 568 (for example, with an insulated conductor (cable)). Coupling ground loop 568 to the ground wellbore below the surface may reduce or eliminate the high field gradient at the surface.
  • the ground wellbore may be at a depth specified, for example, by standard electrical grounding practices known in the art.
  • a subsurface hydrocarbon containing formation may be treated by the in situ heat treatment process to produce mobilized and/or pyrolyzed products from the formation.
  • a subsurface heater may include two or more flexible cable conductors.
  • the flexible cable conductors may be positioned in a tubular.
  • the flexible cable conductors are positioned between two tubulars.
  • the flexible cable conductors are positioned around an exterior surface of a first tubular.
  • the flexible cable conductors and the first tubular may be positioned in a second tubular.
  • the first and second tubular may form a dual-walled wellbore liner.
  • the flexible cable conductors inside the first and second tubular allows the wellbore liner to be operated as a liner heater.
  • the heater includes a plurality of flexible cable conductors positioned between the first and second tubulars. In certain embodiments, the heater includes between 2 and 16, between 4 and 12, or between 6 and 9 flexible cables. In some embodiments, the flexible cable conductors are wound around the inner first tubular in a roughly spiral pattern (for example, a helical pattern). Flexible cables may be formed from single conductors (for example, single-phase conductors) or multiple conductors (for example, three-phase conductors). Installing the flexible cable conductors in the spiral pattern may produce a more uniform temperature profile and/or relieve mechanical stresses on the conductors. The more uniform temperature profile may increase heater life.
  • Spiraled flexible cable conductors, positioned between two tubulars may not have the same tendency to expand and contract apart, which may potentially cause eddy currents.
  • Spiraled flexible cable conductors, positioned between two tubulars may be more easily coiled on a large reel for shipment without the ends of the heaters becoming uneven in length.
  • the tubulars are coiled tubing tubulars. Integrating the flexible heating cable(s) in the first and second tubulars may allow for installation using a coiled tubing spooler, straightener, and/or injector system (for example, a coiled tubing rig).
  • a coiled tubing spooler, straightener, and/or injector system for example, a coiled tubing rig.
  • coiled tubing tubulars may be wound onto the tubing rig during or after construction of the heater and unwound from the tubing rig as the heater is installed into the subsurface formation. This type of installation method may not require additional time typically required to attach the heating cable to a pipe wall during a well intervention, reducing the overall workover cost.
  • the tubing rig may be readily transported from the construction site to the heater installation site using methods known in the art or described herein. Use of the dual walled coiled tubing heating system may allow for retrieval of the system during initial operations.
  • FIG. 87 depicts a cross-sectional representation of heater 412 including nine single-phase flexible cable conductors 380 positioned between first tubular 578 a and second tubular 578 b . Forming the heater such that the flexible cable conductors are in contact with the second tubular 578 b results in the flexible cables providing conductive heat transfer between the first tubular 578 a and the second tubular. In such embodiments, conductive heat transfer functions as the primary method of heat transfer to second tubular 578 b.
  • FIG. 88 depicts a cross-sectional representation of heater 412 including nine single-phase flexible cable conductors 380 positioned between first tubular 578 a and second tubular 578 b with spacers 580 .
  • Spacers 580 may be positioned between first tubular 578 a and second tubular 578 b .
  • the spacers may function to maintain separation between the tubulars and inhibit the flexible cables from contacting second tubular 578 b .
  • radiative heat transfer functions as the primary method of heat transfer to second tubular 578 b.
  • spacers 580 are formed from an insulating material.
  • spacers may be formed from a fibrous ceramic material such as NextelTM 312 (3M Corporation, St. Paul, Minn., U.S.A.), mica tape, or glass fiber.
  • Ceramic material may be made of alumina, alumina-silicate, alumina-borosilicate, silicon nitride, boron nitride, or other suitable high-temperature materials.
  • heat transfer material (for example, heat transfer fluid) is located in the annulus between first tubular 578 a and second tubular 578 b .
  • Heat transfer material may increase the efficiency of the heaters.
  • Heat transfer material includes, but is not limited to, molten metal, molten salt, other heat conducting liquids, or heat conducting gases.
  • the first and/or second tubulars include two or more openings.
  • the openings may allow fluids to be moved upwards and/or downwards through the tubulars.
  • formation fluids may be produced through one of the openings inside the tubulars.
  • Having the openings inside the tubulars may promote heat transfer and/or hydrocarbon accumulation for production assistance (out-flow assurance) or formation heating (in-flow assurance).
  • the use of spacers enhances flow assurance inside the openings by reducing heat losses to the formation and increasing heat transfer to fluids flowing through the openings.
  • the heater includes two or more portions that function to heat at different power levels and, thus, heat at different temperatures. For example, higher power levels and higher temperatures may be generated in portions adjacent the hydrocarbon containing layer. Lower power levels (for example, ⁇ 5% of the higher power level) and lower temperatures may be generated in portions adjacent the overburden.
  • lower power level flexible cables are designed and made utilizing larger diameter and/or different alloys with lower volume resistivities and low-power-producing conductors as compared with the high power level conductors.
  • the power reduction in the overburden is accomplished by using a conductor with a Curie-temperature power-limiting inherent characteristic (for example, low temperature, temperature limiting characteristics).
  • Flexible cables may be formed from single conductors or multiple conductors.
  • the flexible cables used in the heater include single conductor flexible cables installed between the first and second tubulars (for example, as depicted in FIGS. 87 and 88 ).
  • the flexible cables may be electrically connected in as single phase conductors or coupled together in groups of 3 in 3-phase configurations (for example, 3-phase wye configurations).
  • the electrical connections may be completed by bonding two conductors and up to nine or more conductors together.
  • the single conductor flexible cables may be connected together (for example, bonded) at the un-powered end, creating a single phase heating system (two cables connected) and up to, for example, three, 3-phase heating systems (nine cables connected to three power sources). These connections may be located at the subterranean end of the heating system (for example, near the toe of a horizontal heater wellbore).
  • the single-phase cables may be connected to line-to-line voltage (for example, up to 4160 V) for heat generation.
  • 3-phase heaters may be connected electrically on the surface using a 3-phase power transformer. Line-to-neutral voltage for these heaters may be up to about 2402 V (V/ ⁇ square root over (3) ⁇ ) since they are electrically connected at the un-powered subterranean end.
  • the flexible cable used in the heater includes multiple conductor flexible cables installed between the first and second tubulars.
  • the flexible cable may include three multiple conductors configured to be provided power by a 3-phase transformer.
  • FIG. 89 depicts a cross-sectional representation of heater 412 including nine multiple (in FIG. 89 , each flexible cable includes three conductors) flexible cable conductors 380 positioned between first tubular 578 a and second tubular 578 b .
  • FIG. 90 depicts a cross-sectional representation of heater 412 including nine multiple (in FIG. 90 , each flexible cable includes three conductors) flexible cable conductors 380 positioned between first tubular 578 a and second tubular 578 b with spacers 580 .
  • Heater 412 depicted in FIG. 90 includes spacers 580 .
  • the multiple conductor flexible cables depicted in FIGS. 89 and 90 may be coupled together at the un-powered end (for example, bonded at the un-powered end). These connections may be located at the subterranean end of the heating system (for example, near the toe of a horizontal heater wellbore). Connecting the flexible cable conductors at the un-powered end may create electrically independent, individual heating systems that are powered, up to nine or more at a time, to reduce the heat-up time constant for the desired formation temperature or three at a time to maintain the desired formation temperature.
  • the line to neutral voltage for these heaters may be up to about 2402 V (4160/v3) since they are connected at the un-powered subterranean end.
  • the liner heaters may include built-in redundancy in either the single conductor or multiple conductor designs.
  • the single conductor heating cables may be powered to by-pass a non-working flexible cable, creating a 3-phase or single phase heating system.
  • the liner heater is installed in a wellbore.
  • the heater may allow the heat generated to be primarily transferred by conduction, directly into the near well-bore interface.
  • the heat generation system may be in intimate contact with the near wellbore interface such that the operating temperatures of the heating system may be reduced. Reducing operating temperatures of the heater may extend the expected lifetime of the heater. Lower operating temperatures resulting from integrating the electro-thermal heating system within the dual wall coiled tubular liner may increase the reliability of all components such as: a) outer sheath material; b) ceramic insulation; c) conductor(s) material; d) splices; and e) components. Reducing operating temperatures of the heater may inhibit hydrocarbon coking.
  • the liner heater is located in the liner portion of the wellbore, the use of a heating system in the interior of the wellbore may be eliminated. Eliminating the need for a heating system in the interior of the wellbore may allow for unobstructed heated oil production through the wellbore. Eliminating the need for a heating system in the interior of the wellbore may allow for the ability to introduce heated diluents or process-inducing additives to the formation through the interior of the wellbore.
  • portions of the wellbore that extend through the overburden include casings.
  • the casings may include materials that inhibit inductive effects in the casings Inhibiting inductive effects in the casings may inhibit induced currents in the casing and/or reduce heat losses to the overburden.
  • the overburden casings may include non-metallic materials such as fiberglass, polyvinylchloride (PVC), chlorinated PVC (CPVC), high-density polyethylene (HDPE), high temperature polymers (such as nitrogen based polymers), or other high temperature plastics.
  • HDPEs with working temperatures in a usable range include HDPEs available from Dow Chemical Co., Inc. (Midland, Mich., U.S.A.).
  • overburden casings may be made of materials that are spoolable so that the overburden casings can be spooled into the wellbore.
  • overburden casings may include non-magnetic metals such as aluminum or non-magnetic alloys such as manganese steels having at least 10% manganese, iron aluminum alloys with at least 18% aluminum, or austentitic stainless steels such as 304 stainless steel or 316 stainless steel.
  • overburden casings may include carbon steel or other ferromagnetic material coupled on the inside diameter to a highly conductive non-ferromagnetic metal (for example, copper or aluminum) to inhibit inductive effects or skin effects.
  • overburden casings are made of inexpensive materials that may be left in the formation (sacrificial casings).
  • wellheads for the wellbores may be made of one or more non-ferromagnetic materials.
  • FIG. 91 depicts an embodiment of wellhead 392 .
  • the components in the wellheads may include fiberglass, PVC, CPVC, HDPE, high temperature polymers (such as nitrogen based polymers), and/or non-magnetic alloys or metals. Some materials (such as polymers) may be extruded into a mold or reaction injection molded (RIM) into the shape of the wellhead. Forming the wellhead from a mold may be a less expensive method of making the wellhead and save in capital costs for providing wellheads to a treatment site. Using non-ferromagnetic materials in the wellhead may inhibit undesired heating of components in the wellhead.
  • Ferromagnetic materials used in the wellhead may be electrically and/or thermally insulated from other components of the wellhead.
  • an inert gas for example, nitrogen or argon
  • ferromagnetic materials in the wellhead are electrically coupled to a non-ferromagnetic material (for example, copper) to inhibit skin effect heat generation in the ferromagnetic materials in the wellhead.
  • the non-ferromagnetic material is in electrical contact with the ferromagnetic material so that current flows through the non-ferromagnetic material.
  • non-ferromagnetic material 582 is coupled (and electrically coupled) to the inside walls of conduit 382 and wellhead walls 584 .
  • copper may be plasma sprayed, coated, clad, or lined on the inside and/or outside walls of the wellhead.
  • a non-ferromagnetic material such as copper is welded, brazed, clad, or otherwise electrically coupled to the inside and/or outside walls of the wellhead.
  • copper may be swaged out to line the inside walls in the wellhead. Copper may be liquid nitrogen cooled and then allowed to expand to contact and swage against the inside walls of the wellhead.
  • the copper is hydraulically expanded or explosively bonded to contact against the inside walls of the wellhead.
  • two or more substantially horizontal wellbores are branched off of a first substantially vertical wellbore drilled downwards from a first location on a surface of the formation.
  • the substantially horizontal wellbores may be substantially parallel through a hydrocarbon layer.
  • the substantially horizontal wellbores may reconnect at a second substantially vertical wellbore drilled downwards at a second location on the surface of the formation. Having multiple wellbores branching off of a single substantially vertical wellbore drilled downwards from the surface reduces the number of openings made at the surface of the formation.
  • Typical temperature measurement methods may be difficult and/or expensive to implement for use in assessing a temperature profile of a heater located in a subsurface formation for heating in an in situ heat treatment process.
  • the desire is for a temperature profile that includes multiple temperatures along the length or a portion of the heater in the subsurface formation.
  • Thermocouples are one possible solution; however, thermocouples provide only one temperature at one location and one wire is generally needed for each thermocouple. Thus, to obtain a temperature profile along a length of the heater, multiple wires are needed. The risk of failure of one or more of the thermocouples (or their associated wires) is increased with the use of multiple wires in the subsurface wellbore.
  • the fiber optic cable system provides a temperature profile along a length of the heater.
  • Commercially available fiber optic cable systems typically only have operating temperature ranges up to about 300° C. Thus, these systems are not suitable for measurement of higher temperatures encountered while heating the subsurface formation during the in situ heat treatment process.
  • Some experimental fiber optic cable systems are suitable for use at these higher temperatures but these systems may be too expensive for implementation in a commercial process (for example, a large field of heaters).
  • a simple, inexpensive system that allows temperature assessment at one or more locations along a length of the subsurface heater used in the in situ heat treatment process.
  • the assessment of dielectric properties may be used in combination with information about the temperature dependence of dielectric properties to assess a temperature profile of one or more energized heaters (heaters that are powered and providing heat).
  • the temperature dependence data of the dielectric properties may be found from simulation and/or experimentation. Examples of dielectric properties of the insulation that may be assessed over time include, but are not limited to, dielectric constant and loss tangent.
  • FIG. 92 depicts an example of a plot of dielectric constant versus temperature for magnesium oxide insulation in one embodiment of an insulated conductor heater.
  • FIG. 93 depicts an example of a plot of loss tangent (tan ⁇ ) versus temperature for magnesium oxide insulation in one embodiment of an insulated conductor heater.
  • the temperature dependent behavior of a dielectric property may vary based on certain factors. Factors that may affect the temperature dependent behavior of the dielectric property include, but are not limited to, the type of insulation, the dimensions of the insulation, the time the insulation is exposed to environment (for example, heat from the heater), the composition (chemistry) of the insulation, and the compaction of the insulation. Thus, it is typically necessary to measure (either by simulation and/or experimentation) the temperature dependent behavior of the dielectric property for the embodiment of insulation that is to be used in a selected heater.
  • one or more dielectric properties of the insulation in a heater having electrical insulation are assessed (measured) and compared to temperature dependence data of the dielectric properties to assess (determine) a temperature profile along a length of the heater (for example, the entire length of the heater or a portion of the heater).
  • a temperature profile along a length of the heater for example, the entire length of the heater or a portion of the heater.
  • the temperature of an insulated conductor heater such as a mineral insulated (MI) cable heater
  • MI mineral insulated
  • Examples of insulated conductor heaters are depicted in FIGS. 32A , 32 B, and 33 . Since the temperature dependence of the dielectric property measured is known or estimated from simulation and/or experimentation, the measured dielectric property at a location along the heater may be used to assess the temperature of the heater at that location. Using techniques that measure the dielectric properties at multiple locations along a length of the heater (as is possible with current techniques), a temperature profile along that heater length may be provided.
  • the dielectric properties are more sensitive to temperature at higher temperatures (for example, above about 900° F., as shown in FIGS. 92 and 93 ).
  • the temperature of a portion of the insulated conductor heater is assessed by measurement of the dielectric properties at temperatures above about 400° C. (about 760° F.).
  • the temperature of the portion may be assessed by measurement of the dielectric properties at temperatures ranging from about 400° C., about 450° C., or about 500° C. to about 800° C., about 850° C., or about 900° C. These ranges of temperatures are above temperatures that can be measured using commercially available fiber optic cable systems.
  • a fiber optic cable system suitable for use in the higher temperature ranges may, however, provide measurements with higher spatial resolution than temperature assessment by measurement of the dielectric properties.
  • the fiber optic cable system operable in the higher temperature ranges may be used to calibrate temperature assessment by measurement of dielectric properties.
  • temperature assessment by measurement of the dielectric properties may be less accurate. Temperature assessment by measurement of the dielectric properties may, however, provide a reasonable estimate or “average” temperature of portions of the heater. The average temperature assessment may be used to assess whether the heater is operating in a safe range. Typically, a heater operating at temperatures below about 400° C., below about 450° C., or below about 500° C. is operating in the safe range.
  • Temperature assessment by measurement of dielectric properties may provide a temperature profile along a length or portion of the insulated conductor heater (temperature measurements distributed along the length or portion of the heater). Measuring the temperature profile is more useful for monitoring and controlling the heater as compared to taking temperature measurements at only selected locations (such as temperature measurement with thermocouples). Multiple thermocouples may be used to provide a temperature profile. Multiple wires (one for each thermocouple), however, would be needed. Temperature assessment by measurement of dielectric properties uses only one wire for measurement of the temperature profile, which is simpler and less expensive than using multiple thermocouples. In some embodiments, one or more thermocouples placed at selected locations are used to calibrate temperature assessment by measurement of dielectric properties.
  • the dielectric properties of the insulation in an insulated conductor heater are assessed (measured) over a period of time to assess the temperature and operating characteristics of the heater over the period of time.
  • the dielectric properties may be assessed continuously (or substantially continuously) to provide real-time monitoring of the dielectric properties and the temperature. Monitoring of the dielectric properties and the temperature may be used to assess the condition of the heater during operation of the heater. For example, comparison of the assessed properties at specific locations versus the average properties over the length of the heater may provide information on the location of hot spots or defects in the heater.
  • the dielectric properties of the insulation change over time.
  • the dielectric properties may change over time because of changes in the oxygen concentration in the insulation over time and/or changes in the water content in the insulation over time.
  • Oxygen in the insulation may be consumed by chromium or other metals used in the insulated conductor heater.
  • the oxygen concentration decreases with time in the insulation and affects the dielectric properties of the insulation.
  • the changes in dielectric properties over time may be measured and compensated for through experimental and/or simulated data.
  • the insulated conductor heater to be used for temperature assessment may be heated in an oven or other apparatus and the changes in dielectric properties can be measured over time at various temperatures and/or at constant temperatures.
  • thermocouples may be used to calibrate the assessment of dielectric properties changes over time by comparison of thermocouple data to temperature assessed by the dielectric properties.
  • temperature assessment by measurement of dielectric properties is performed using a computational system such as a workstation or computer.
  • the computational system may receive measurements (assessments) of the dielectric properties along the heater and correlate these measured dielectric properties to assess temperatures at one or more locations on the heater.
  • the computational system may store data about the relationship of the dielectric properties to temperature (such as the data depicted in FIGS. 92 and 93 ) and/or time, and use this stored data to calculate the temperatures on the heater based on the measured dielectric properties.
  • temperature assessment by dielectric properties measurement is performed on an energized heater providing heat to the subsurface formation (for example, an insulated conductor heater provided with electric power to resistively heat and provide heat to the subsurface formation). Assessing temperature on the energized heater allows for detection of defects in the insulation on the device actually providing heat to the formation. Assessing temperature on the energized heater, however, may be more difficult due to attenuation of signal along the heater because the heater is resistively heating. This attenuation may inhibit seeing further along the length of the heater (deeper into the formation along the heater).
  • temperatures in the upper sections of heaters may be more important for assessment because these sections have higher voltages applied to the heater, are at higher temperatures, and are at higher risk for failure or generation of hot spots.
  • the signal attenuation in the temperature assessment by dielectric properties measurement may not be as significant a factor in these upper sections because of the proximity of these sections to the surface.
  • power to the insulated conductor heater is turned off before performing the temperature assessment. Power is then returned to the insulated conductor heater after the temperature assessment.
  • the insulated conductor heater is subjected to a heating on/off cycle to assess temperature. This on/off cycle may, however, reduce the lifetime of the heater due to the thermal cycling.
  • the heater may cool off during the non-energized time period and provide less accurate temperature information (less accurate information on the actual working temperature of the heater).
  • temperature assessment by dielectric properties measurement is performed on an insulated conductor that is not to be used for heating or not configured for heating.
  • an insulated conductor may be a separate insulated conductor temperature probe.
  • the insulated conductor temperature probe is a non-energized heater (for example, an insulated conductor heater not powered).
  • the insulated conductor temperature probe may be a stand-alone device that can be located in an opening in the subsurface formation to measure temperature in the opening.
  • the insulated conductor temperature probe is a looped probe that goes out and back into the opening with signals transmitted in one direction on the probe.
  • the insulated conductor temperature probe is a single hanging probe with the signal transmitted along the core and returned along the sheath of the insulated conductor.
  • the insulated conductor temperature probe includes a copper core (to provide better conductance to the end of the cable and better spatial resolution) surrounded by magnesium oxide insulation and an outer metal sheath.
  • the outer metal sheath may be made of any material suitable for use in the subsurface opening.
  • the outer metal sheath may be a stainless steel sheath or an inner sheath of copper wrapped with an outer sheath of stainless steel.
  • the insulated conductor temperature probe operates up to temperatures and pressures that can be withstood by the outer metal sheath.
  • the insulated conductor temperature probe is located adjacent to or near an energized heater in the opening to measure temperatures along the energized heater. There may be a temperature difference between the insulated conductor temperature probe and the energized heater (for example, between about 50° C. and 100° C. temperature differences). This temperature difference may be assessed through experimentation and/or simulation and accounted for in the temperature measurements. The temperature difference may also be calibrated using one or more thermocouples attached to the energized heater.
  • thermocouples are attached to the insulated conductor used for temperature assessment (either an energized insulated conductor heater or a non-energized insulated conductor temperature probe).
  • the attached thermocouples may be used for calibration and/or backup measurement of the temperature assessed on the insulated conductor by dielectric property measurement.
  • calibration and/or backup temperature indication is achieved by assessment of the resistance variation of the core of the insulated conductor at a given applied voltage. Temperature may be assessed by knowing the resistance versus temperature profile of the core material at the given voltage.
  • the insulated conductor is a loop and current induced in the loop from energized heaters in the subsurface opening provides input for the resistance measurement.
  • insulation material properties in the insulated conductor are varied to provide different sensitivities to temperature for the insulated conductor.
  • insulation material properties that may be varied include, but are not limited to, the chemical and phase composition, the microstructure, and/or the mixture of insulating materials. Varying the insulation material properties in the insulated conductor allows the insulated conductor to be tuned to a selected temperature range. The selected temperature range may be selected, for example, for a desired application of the insulated conductor.
  • insulation material properties are varied along the length of the insulated conductor (the insulation material properties are different at selected points within the insulated conductor). Varying properties of the insulation material at known locations along the length of the insulated conductor allows the measurement of the dielectric properties to give location information and/or provide for self-calibration of the insulated conductor in addition to providing temperature assessment.
  • the insulated conductor includes a portion with insulation material properties that allow the portion to act as a reflector. The reflector portion may be used to limit temperature assessment to specific portions of the insulated conductor (for example, a specific length of insulated conductor). One or more reflector portions may be used to provide spatial markers along the length of the insulated conductor.
  • Varying the insulation material properties adjusts the activation energy of the insulation material. Typically, increasing the activation energy of the insulation material reduces attenuation in the insulation material and provides better spatial resolution. Lowering the activation energy typically provides better temperature sensitivity.
  • the activation energy may be raised or lowered, for example, by adding different components to the insulation material. For example, adding certain components to magnesium oxide insulation will lower the activation energy. Examples of components that may be added to magnesium oxide to lower the activation energy include, but are not limited to, titanium oxide, nickel oxide, and iron oxide.
  • temperature is assessed using two or more insulated conductors.
  • the insulated conductors may have different activation energies to provide a variation in spatial resolution and temperature sensitivity to more accurately assess temperature in the subsurface opening.
  • the higher activation energy insulated conductor may be used to provide better spatial resolution and identify the location of hot spots or other temperature variations more accurately while the lower activation energy insulated conductor may be used to provide more accurate temperature measurement at those locations.
  • temperature is assessed by assessing leakage current from the insulated conductor. Temperature dependence data of the leakage current may be used to assess the temperature based on assessed (measured) leakage current from the insulated conductor. The measured leakage current may be used in combination with information about the temperature dependence of the leakage current to assess a temperature profile of one or more heaters or insulated conductors located in a subsurface opening. The temperature dependence data of the leakage current may be found from simulation and/or experimentation. In certain embodiments, the temperature dependence data of the leakage current is also dependent on the voltage applied to the heater.
  • FIG. 94 depicts an example of a plot of leakage current (mA) versus temperature (° F.) for magnesium oxide insulation in one embodiment of an insulated conductor heater at different applied voltages.
  • Plot 586 is for an applied voltage of 4300 V.
  • Plot 588 is for an applied voltage of 3600 V.
  • Plot 590 is for an applied voltage of 2800 V.
  • Plot 592 is for an applied voltage of 2100 V.
  • the leakage current is more sensitive to temperature at higher temperatures (for example, above about 950° F., as shown in FIG. 94 ).
  • the temperature of a portion of the insulated conductor heater is assessed by measurement of the leakage current at temperatures above about 500° C. (about 932° F.).
  • a temperature profile along a length of the heater may be obtained by measuring the leakage current along the length of the heater using techniques known in the art.
  • assessment of temperature by measuring the leakage current is used in combination with temperature assessment by dielectric properties measurement.
  • temperature assessment by measurement of the leakage current may be used to calibrate and/or backup temperature assessments made by measurement of dielectric properties.
  • an insulated conductor using salt as the electrical insulator is used for temperature measurement.
  • the salt becomes an electrical conductor above the melting temperature (T m ) of the salt and allows current to flow through the electrical insulator.
  • FIG. 95 depicts an embodiment of insulated conductor 410 with salt used as electrical insulator 364 .
  • Core 374 is copper or another suitable electrical conductor.
  • Jacket 370 is stainless steel or another suitable corrosion-resistant electrical conductor. In one embodiment, core 374 is 0.125′′ (about 0.3175 cm) diameter copper surrounded by electrical insulator 364 .
  • Electrical insulator 364 is 0.1′′ (about 0.25 cm) thick salt insulation surrounded by jacket 370 .
  • Jacket 370 is 0.1′′ (about 0.25 cm) thick stainless steel. The outer diameter of insulated conductor 410 is then 0.525′′ (about 1.33 cm).
  • electrical insulator 364 includes a salt with a melting temperature (T m ) at a desired temperature.
  • the desired temperature may be a temperature in the range of operation of a subsurface heater or a maximum temperature desired in the opening.
  • the desired temperature may be above about 300° C. or in a range between 300° C., 400° C., about 450° C., or about 500° C. and about 800° C., about 850° C., or about 900° C.
  • magnesium oxide such as porous magnesium oxide
  • the magnesium oxide maintains the integrity and structure of insulated conductor 410 when the salt melts. Porous magnesium oxide allows for electrical connectivity between core 374 and jacket 370 by having the salt distributed in the pores of the magnesium oxide.
  • a mixture of two or more salts is used in electrical insulator 364 of insulated conductor 410 . Varying the composition of the salts in the mixture allows for adjusting and tuning the melting temperature of the mixture to a desired temperature. In some embodiments, the composition of eutectic mixtures of salts is adjusted and tuned to the desired temperature. Eutectic mixtures may allow for finer adjustment and tuning to the desired temperature. Examples of eutectic mixtures that may be used include, but are not limited to, K 2 CO 3 :Na 2 CO 3 :Li 2 CO 3 and KNO 3 :NaNO 3 .
  • Insulated conductor 410 may be coupled to or located near one or more heaters in a subsurface wellbore to assess the temperature at one or more locations along the length of the insulated conductor at or near the heaters.
  • insulated conductor 410 is similar in length to the heaters in the subsurface wellbore.
  • insulated conductor 410 has a shorter length than the heaters.
  • more than one insulated conductor 410 may be used in the wellbore to assess the temperature at different locations in the wellbore and/or at different temperatures.
  • FIG. 96 depicts an embodiment of insulated conductor 410 located proximate heaters 412 in wellbore 490 .
  • insulated conductor 410 is coupled to one or more of heaters 412 .
  • insulated conductor 410 may be strapped to the assembly of heaters 412 .
  • Heaters 412 may be insulated conductor heaters, conductor-in-conduit heaters, other types of heaters described herein, or combinations thereof.
  • hot spot 594 may develop at some location along the insulated conductor 410 .
  • Hot spot 594 is hotter than other portions along the length of insulated conductor 410 .
  • Hot spot 594 may be caused by a hot spot developing on or near one or more heaters located in the wellbore (for example, heaters 412 depicted in FIG. 96 ).
  • the salt melts and becomes a liquid or molten salt.
  • the salt becomes an electrical conductor with resistivities below 1 ⁇ cm.
  • current begins to flow between the surface and hot spot 594 , as shown by the arrows in FIG. 97 .
  • the distance from the surface to hot spot 594 may be assessed by the measured current at the surface.
  • multiple hotspots may be located using insulated conductor 410 .
  • Time domain reflectometry may be used to locate multiple hotspots along insulated conductor 410 because the insulated conductor has a coaxial geometry.
  • FIG. 98 shows insulated conductor 410 with multiple hot spots 594 A, 594 B.
  • Incident pulse 596 is provided to insulated conductor 410 .
  • Reflected pulses 598 A, 594 B are generated at corresponding hot spots 594 A, 594 B.
  • the conductive molten salt at hot spots 594 A, 594 B provides a strong impedance mismatch for the reflections.
  • the reflection coefficient for each hotspot can be assessed using EQN. 8:
  • Z HS is the impedance of the hotspot
  • Z 0 is the impedance of the insulated conductor (cable).
  • the location of the hotspots (X HSa , X HSb ) can be assessed by assessing (measuring) the transit time, ⁇ , between the incident and reflected pulses and using EQN. 9:
  • v c is the speed of light
  • ⁇ is the dielectric constant of the salt insulation, which depends upon the salt used and compaction of the insulated conductor.
  • a hairpin insulated conductor configuration is used. The hairpin configuration allows for testing from both ends of the insulated conductor and increases the accuracy of hotspot location.
  • assessment of the locations of hotspots by assessing the current or pulses applied to salt based insulated conductor 410 is used in combination with temperature assessment using thermocouples and/or fiber optic cable temperature sensor.
  • the thermocouples and/or fiber optic cable temperature sensor may be used for calibration and/or backup measurement of the temperature assessment using the salt based insulated conductor.
  • a temperature limited heater is utilized for heavy oil applications (for example, treatment of relatively permeable formations or tar sands formations).
  • a temperature limited heater may provide a relatively low Curie temperature and/or phase transformation temperature range so that a maximum average operating temperature of the heater is less than 350° C., 300° C., 250° C., 225° C., 200° C., or 150° C.
  • a maximum temperature of the temperature limited heater is less than about 250° C. to inhibit olefin generation and production of other cracked products.
  • a maximum temperature of the temperature limited heater is above about 250° C. to produce lighter hydrocarbon products.
  • the maximum temperature of the heater may be at or less than about 500° C.
  • a heater may heat a volume of formation adjacent to a production wellbore (a near production wellbore region) so that the temperature of fluid in the production wellbore and in the volume adjacent to the production wellbore is less than the temperature that causes degradation of the fluid.
  • the heat source may be located in the production wellbore or near the production wellbore. In some embodiments, the heat source is a temperature limited heater. In some embodiments, two or more heat sources may supply heat to the volume. Heat from the heat source may reduce the viscosity of crude oil in or near the production wellbore. In some embodiments, heat from the heat source mobilizes fluids in or near the production wellbore and/or enhances the flow of fluids to the production wellbore.
  • reducing the viscosity of crude oil allows or enhances gas lifting of heavy oil (at most about 10° API gravity oil) or intermediate gravity oil (approximately 12° to 20° API gravity oil) from the production wellbore.
  • the initial API gravity of oil in the formation is at most 10°, at most 20°, at most 25°, or at most 30°.
  • the viscosity of oil in the formation is at least 0.05 Pa ⁇ s (50 cp). In some embodiments, the viscosity of oil in the formation is at least 0.10 Pa ⁇ s (100 cp), at least 0.15 Pa ⁇ s (150 cp), or at least at least 0.20 Pa ⁇ s (200 cp).
  • the rate of production of oil from the formation may be increased by raising the temperature at or near a production wellbore to reduce the viscosity of the oil in the formation in and adjacent to the production wellbore.
  • the rate of production of oil from the formation is increased by 2 times, 3 times, 4 times, or greater over standard cold production with no external heating of formation during production.
  • Certain formations may be more economically viable for enhanced oil production using the heating of the near production wellbore region. Formations that have a cold production rate approximately between 0.05 m 3 /(day per meter of wellbore length) and 0.20 m 3 /(day per meter of wellbore length) may have significant improvements in production rate using heating to reduce the viscosity in the near production wellbore region.
  • production wells up to 775 m, up to 1000 m, or up to 1500 m in length are used.
  • Heating the near production wellbore region may be used in formations where the cold production rate is not between 0.05 m 3 /(day per meter of wellbore length) and 0.20 m 3 /(day per meter of wellbore length), but heating such formations may not be as economically favorable.
  • Higher cold production rates may not be significantly increased by heating the near wellbore region, while lower production rates may not be increased to an economically useful value.
  • Non-temperature limited heaters can cause coking of oil at or near the production well if the heater overheats the oil because the heaters are at too high a temperature. Higher temperatures in the production well may also cause brine to boil in the well, which may lead to scale formation in the well. Non-temperature limited heaters that reach higher temperatures may also cause damage to other wellbore components (for example, screens used for sand control, pumps, or valves). Hot spots may be caused by portions of the formation expanding against or collapsing on the heater.
  • the heater (either the temperature limited heater or another type of non-temperature limited heater) has sections that are lower because of sagging over long heater distances. These lower sections may sit in heavy oil or bitumen that collects in lower portions of the wellbore. At these lower sections, the heater may develop hot spots due to coking of the heavy oil or bitumen. A standard non-temperature limited heater may overheat at these hot spots, thus producing a non-uniform amount of heat along the length of the heater. Using the temperature limited heater may inhibit overheating of the heater at hot spots or lower sections and provide more uniform heating along the length of the wellbore.
  • fluids in the relatively permeable formation containing heavy hydrocarbons are produced with little or no pyrolyzation of hydrocarbons in the formation.
  • the relatively permeable formation containing heavy hydrocarbons is a tar sands formation.
  • the formation may be a tar sands formation such as the Athabasca tar sands formation in Alberta, Canada or a carbonate formation such as the Grosmont carbonate formation in Alberta, Canada.
  • the fluids produced from the formation are mobilized fluids. Producing mobilized fluids may be more economical than producing pyrolyzed fluids from the tar sands formation. Producing mobilized fluids may also increase the total amount of hydrocarbons produced from the tar sands formation.
  • FIGS. 99-102 depict side view representations of embodiments for producing mobilized fluids from tar sands formations.
  • heaters 412 have substantially horizontal heating sections in hydrocarbon layer 388 (as shown, the heaters have heating sections that go into and out of the page).
  • Hydrocarbon layer 388 may be below overburden 400 .
  • FIG. 99 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a relatively thin hydrocarbon layer.
  • FIG. 100 depicts a side view representation of an embodiment for producing mobilized fluids from a hydrocarbon layer that is thicker than the hydrocarbon layer depicted in FIG. 99 .
  • FIG. 101 depicts a side view representation of an embodiment for producing mobilized fluids from a hydrocarbon layer that is thicker than the hydrocarbon layer depicted in FIG. 100 .
  • FIG. 102 depicts a side view representation of an embodiment for producing mobilized fluids from a tar sands formation with a hydrocarbon layer that has a shale break.
  • heaters 412 are placed in an alternating triangular pattern in hydrocarbon layer 388 .
  • heaters 412 are placed in an alternating triangular pattern in hydrocarbon layer 388 that repeats vertically to encompass a majority or all of the hydrocarbon layer.
  • the alternating triangular pattern of heaters 412 in hydrocarbon layer 388 repeats uninterrupted across shale break 600 .
  • heaters 412 may be equidistantly spaced from each other. In the embodiments depicted in FIGS.
  • the number of vertical rows of heaters 412 depends on factors such as, but not limited to, the desired spacing between the heaters, the thickness of hydrocarbon layer 388 , and/or the number and location of shale breaks 600 .
  • heaters 412 are arranged in other patterns.
  • heaters 412 may be arranged in patterns such as, but not limited to, hexagonal patterns, square patterns, or rectangular patterns.
  • heaters 412 provide heat that mobilizes hydrocarbons (reduces the viscosity of the hydrocarbons) in hydrocarbon layer 388 .
  • heaters 412 provide heat that reduces the viscosity of the hydrocarbons in hydrocarbon layer 388 below about 0.50 Pa ⁇ s (500 cp), below about 0.10 Pa ⁇ s (100 cp), or below about 0.05 Pa ⁇ s (50 cp).
  • the spacing between heaters 412 and/or the heat output of the heaters may be designed and/or controlled to reduce the viscosity of the hydrocarbons in hydrocarbon layer 388 to desirable values.
  • Heat provided by heaters 412 may be controlled so that little or no pyrolyzation occurs in hydrocarbon layer 388 .
  • Superposition of heat between the heaters may create one or more drainage paths (for example, paths for flow of fluids) between the heaters.
  • production wells 206 A and/or production wells 206 B are located proximate heaters 412 so that heat from the heaters superimposes over the production wells. The superimposition of heat from heaters 412 over production wells 206 A and/or production wells 206 B creates one or more drainage paths from the heaters to the production wells. In certain embodiments, one or more of the drainage paths converge.
  • the drainage paths may converge at or near a bottommost heater and/or the drainage paths may converge at or near production wells 206 A and/or production wells 206 B.
  • Fluids mobilized in hydrocarbon layer 388 tend to flow towards the bottommost heaters 412 , production wells 206 A and/or production wells 206 B in the hydrocarbon layer because of gravity and the heat and pressure gradients established by the heaters and/or the production wells.
  • the drainage paths and/or the converged drainage paths allow production wells 206 A and/or production wells 206 B to collect mobilized fluids in hydrocarbon layer 388 .
  • hydrocarbon layer 388 has sufficient permeability to allow mobilized fluids to drain to production wells 206 A and/or production wells 206 B.
  • hydrocarbon layer 388 may have a permeability of at least about 0.1 darcy, at least about 1 darcy, at least about 10 darcy, or at least about 100 darcy.
  • hydrocarbon layer 388 has a relatively large vertical permeability to horizontal permeability ratio (K v /K h ).
  • hydrocarbon layer 388 may have a K v /K h ratio between about 0.01 and about 2, between about 0.1 and about 1, or between about 0.3 and about 0.7.
  • fluids are produced through production wells 206 A located near heaters 412 in the lower portion of hydrocarbon layer 388 .
  • fluids are produced through production wells 206 B located below and approximately midway between heaters 412 in the lower portion of hydrocarbon layer 388 .
  • At least a portion of production wells 206 A and/or production wells 206 B may be oriented substantially horizontal in hydrocarbon layer 388 (as shown in FIGS. 99-102 , the production wells have horizontal portions that go into and out of the page).
  • Production wells 206 A and/or 206 B may be located proximate lower portion heaters 412 or the bottommost heaters.
  • production wells 206 A are positioned substantially vertically below the bottommost heaters in hydrocarbon layer 388 .
  • Production wells 206 A may be located below heaters 412 at the bottom vertex of a pattern of the heaters (for example, at the bottom vertex of the triangular pattern of heaters depicted in FIGS. 99-102 ). Locating production wells 206 A substantially vertically below the bottommost heaters may allow for efficient collection of mobilized fluids from hydrocarbon layer 388 .
  • the bottommost heaters are located between about 2 m and about 10 m from the bottom of hydrocarbon layer 388 , between about 4 m and about 8 m from the bottom of the hydrocarbon layer, or between about 5 m and about 7 m from the bottom of the hydrocarbon layer.
  • production wells 206 A and/or production wells 206 B are located at a distance from the bottommost heaters 412 that allows heat from the heaters to superimpose over the production wells but at a distance from the heaters that inhibits coking at the production wells.
  • Production wells 206 A and/or production wells 206 B may be located a distance from the nearest heater (for example, the bottommost heater) of at most 3 ⁇ 4 of the spacing between heaters in the pattern of heaters (for example, the triangular pattern of heaters depicted in FIGS. 99-102 ). In some embodiments, production wells 206 A and/or production wells 206 B are located a distance from the nearest heater of at most 2 ⁇ 3, at most 1 ⁇ 2, or at most 1 ⁇ 3 of the spacing between heaters in the pattern of heaters.
  • production wells 206 A and/or production wells 206 B are located between about 2 m and about 10 m from the bottommost heaters, between about 4 m and about 8 m from the bottommost heaters, or between about 5 m and about 7 m from the bottommost heaters.
  • Production wells 206 A and/or production wells 206 B may be located between about 0.5 m and about 8 m from the bottom of hydrocarbon layer 388 , between about 1 m and about 5 m from the bottom of the hydrocarbon layer, or between about 2 m and about 4 m from the bottom of the hydrocarbon layer.
  • At least some production wells 206 A are located substantially vertically below heaters 412 near shale break 600 , as depicted in FIG. 102 .
  • Production wells 206 A may be located between heaters 412 and shale break 600 to produce fluids that flow and collect above the shale break.
  • Shale break 600 may be an impermeable barrier in hydrocarbon layer 388 .
  • shale break 600 has a thickness between about 1 m and about 6 m, between about 2 m and about 5 m, or between about 3 m and about 4 m.
  • Production wells 206 A between heaters 412 and shale break 600 may produce fluids from the upper portion of hydrocarbon layer 388 (above the shale break) and production wells 206 A below the bottommost heaters in the hydrocarbon layer may produce fluids from the lower portion of the hydrocarbon layer (below the shale break), as depicted in FIG. 102 .
  • two or more shale breaks may exist in a hydrocarbon layer.
  • production wells are placed at or near each of the shale breaks to produce fluids flowing and collecting above the shale breaks.
  • shale break 600 breaks down (is desiccated or decomposes) as the shale break is heated by heaters 412 on either side of the shale break.
  • shale break 600 breaks down, the permeability of the shale break increases and fluids flow through the shale break. Once fluids are able to flow through shale break 600 , production wells above the shale break may not be needed for production as fluids can flow to production wells at or near the bottom of hydrocarbon layer 388 and be produced there.
  • the bottommost heaters above shale break 600 are located between about 2 m and about 10 m from the shale break, between about 4 m and about 8 m from the bottom of the shale break, or between about 5 m and about 7 m from the shale break.
  • Production wells 206 A may be located between about 2 m and about 10 m from the bottommost heaters above shale break 600 , between about 4 m and about 8 m from the bottommost heaters above the shale break, or between about 5 m and about 7 m from the bottommost heaters above the shale break.
  • Production wells 206 A may be located between about 0.5 m and about 8 m from shale break 600 , between about 1 m and about 5 m from the shale break, or between about 2 m and about 4 m from the shale break.
  • heat is provided in production wells 206 A and/or production wells 206 B, depicted in FIGS. 99-102 .
  • Providing heat in production wells 206 A and/or production wells 206 B may maintain and/or enhance the mobility of the fluids in the production wells.
  • Heat provided in production wells 206 A and/or production wells 206 B may superimpose with heat from heaters 412 to create the flow path from the heaters to the production wells.
  • production wells 206 A and/or production wells 206 B include a pump to move fluids to the surface of the formation.
  • the viscosity of fluids (oil) in production wells 206 A and/or production wells 206 B is lowered using heaters and/or diluent injection (for example, using a conduit in the production wells for injecting the diluent).
  • in situ heat treatment of the relatively permeable formation containing hydrocarbons includes heating the formation to visbreaking temperatures.
  • the formation may be heated to temperatures between about 100° C. and 260° C., between about 150° C. and about 250° C., between about 200° C. and about 240° C., between about 205° C. and 230° C., between about 210° C. and 225° C.
  • the formation is heated to a temperature of about 220° C.
  • the formation is heated to a temperature of about 230° C.
  • fluids in the formation have a reduced viscosity (versus their initial viscosity at initial formation temperature) that allows fluids to flow in the formation.
  • the reduced viscosity at visbreaking temperatures may be a permanent reduction in viscosity as the hydrocarbons go through a step change in viscosity at visbreaking temperatures (versus heating to mobilization temperatures, which may only temporarily reduce the viscosity).
  • the visbroken fluids may have API gravities that are relatively low (for example, at most about 10°, about 12°, about 15°, or about 19° API gravity), but the API gravities are higher than the API gravity of non-visbroken fluid from the formation.
  • the non-visbroken fluid from the formation may have an API gravity of 7° or less.
  • heaters in the formation are operated at full power output to heat the formation to visbreaking temperatures or higher temperatures. Operating at full power may rapidly increase the pressure in the formation.
  • fluids are produced from the formation to maintain a pressure in the formation below a selected pressure as the temperature of the formation increases.
  • the selected pressure is a fracture pressure of the formation. In certain embodiments, the selected pressure is between about 1000 kPa and about 15000 kPa, between about 2000 kPa and about 10000 kPa, or between about 2500 kPa and about 5000 kPa. In one embodiment, the selected pressure is about 10000 kPa. Maintaining the pressure as close to the fracture pressure as possible may minimize the number of production wells needed for producing fluids from the formation.
  • treating the formation includes maintaining the temperature at or near visbreaking temperatures (as described above) during the entire production phase while maintaining the pressure below the fracture pressure.
  • the heat provided to the formation may be reduced or eliminated to maintain the temperature at or near visbreaking temperatures.
  • Heating to visbreaking temperatures but maintaining the temperature below pyrolysis temperatures or near pyrolysis temperatures inhibits coke formation and/or higher level reactions.
  • Heating to visbreaking temperatures at higher pressures keeps produced gases in the liquid oil (hydrocarbons) in the formation and increases hydrogen reduction in the formation with higher hydrogen partial pressures. Heating the formation to only visbreaking temperatures also uses less energy input than heating the formation to pyrolysis temperatures.
  • Fluids produced from the formation may include visbroken fluids, mobilized fluids, and/or pyrolyzed fluids.
  • a produced mixture that includes these fluids is produced from the formation.
  • the produced mixture may have assessable properties (for example, measurable properties).
  • the produced mixture properties are determined by operating conditions in the formation being treated (for example, temperature and/or pressure in the formation). In certain embodiments, the operating conditions may be selected, varied, and/or maintained to produce desirable properties in hydrocarbons in the produced mixture.
  • the produced mixture may include hydrocarbons that have properties that allow the mixture to be easily transported (for example, sent through a pipeline without adding diluent or blending the mixture and/or resulting hydrocarbons with another fluid).
  • the pressure in the formation is reduced.
  • the pressure in the formation is reduced at temperatures above visbreaking temperatures. Reducing the pressure at higher temperatures allows more of the hydrocarbons in the formation to be converted to higher quality hydrocarbons by visbreaking and/or pyrolysis. Allowing the formation to reach higher temperatures before pressure reduction, however, may increase the amount of carbon dioxide produced and/or the amount of coking in the formation. For example, in some formations, coking of bitumen (at pressures above 700 kPa) begins at about 280° C. and reaches a maximum rate at about 340° C. At pressures below about 700 kPa, the coking rate in the formation is minimal Allowing the formation to reach higher temperatures before pressure reduction may decrease the amount of hydrocarbons produced from the formation.
  • the temperature in the formation (for example, an average temperature of the formation) when the pressure in the formation is reduced is selected to balance one or more factors.
  • the factors considered may include: the quality of hydrocarbons produced, the amount of hydrocarbons produced, the amount of carbon dioxide produced, the amount hydrogen sulfide produced, the degree of coking in the formation, and/or the amount of water produced.
  • Experimental assessments using formation samples and/or simulated assessments based on the formation properties may be used to assess results of treating the formation using the in situ heat treatment process. These results may be used to determine a selected temperature, or temperature range, for when the pressure in the formation is to be reduced.
  • the selected temperature, or temperature range may also be affected by factors such as, but not limited to, hydrocarbon or oil market conditions and other economic factors.
  • the selected temperature is in a range between about 275° C. and about 305° C., between about 280° C. and about 300° C., or between about 285° C. and about 295° C.
  • an average temperature in the formation is assessed from an analysis of fluids produced from the formation.
  • the average temperature of the formation may be assessed from an analysis of the fluids that have been produced to maintain the pressure in the formation below the fracture pressure of the formation.
  • values of the hydrocarbon isomer shift in fluids (for example, gases) produced from the formation is used to indicate the average temperature in the formation.
  • Experimental analysis and/or simulation may be used to assess one or more hydrocarbon isomer shifts and relate the values of the hydrocarbon isomer shifts to the average temperature in the formation.
  • the assessed relation between the hydrocarbon isomer shifts and the average temperature may then be used in the field to assess the average temperature in the formation by monitoring one or more of the hydrocarbon isomer shifts in fluids produced from the formation.
  • the pressure in the formation is reduced when the monitored hydrocarbon isomer shift reaches a selected value.

Landscapes

  • Engineering & Computer Science (AREA)
  • Geology (AREA)
  • Life Sciences & Earth Sciences (AREA)
  • Mining & Mineral Resources (AREA)
  • Geochemistry & Mineralogy (AREA)
  • Environmental & Geological Engineering (AREA)
  • General Life Sciences & Earth Sciences (AREA)
  • Physics & Mathematics (AREA)
  • Fluid Mechanics (AREA)
  • Microelectronics & Electronic Packaging (AREA)
  • Production Of Liquid Hydrocarbon Mixture For Refining Petroleum (AREA)
  • Earth Drilling (AREA)
  • Physical Or Chemical Processes And Apparatus (AREA)
  • Pipe Accessories (AREA)
  • Investigation Of Foundation Soil And Reinforcement Of Foundation Soil By Compacting Or Drainage (AREA)
  • Treatment Of Sludge (AREA)
  • Monitoring And Testing Of Nuclear Reactors (AREA)
  • Road Paving Structures (AREA)
US12/576,722 2008-10-13 2009-10-09 Using self-regulating nuclear reactors in treating a subsurface formation Abandoned US20100101783A1 (en)

Priority Applications (2)

Application Number Priority Date Filing Date Title
US12/576,722 US20100101783A1 (en) 2008-10-13 2009-10-09 Using self-regulating nuclear reactors in treating a subsurface formation
US15/085,561 US20160281482A1 (en) 2008-10-13 2016-03-30 Circulated heated transfer fluid heating of subsurface hydrocarbon formations

Applications Claiming Priority (3)

Application Number Priority Date Filing Date Title
US10497408P 2008-10-13 2008-10-13
US16849809P 2009-04-10 2009-04-10
US12/576,722 US20100101783A1 (en) 2008-10-13 2009-10-09 Using self-regulating nuclear reactors in treating a subsurface formation

Related Child Applications (1)

Application Number Title Priority Date Filing Date
US15/085,561 Continuation US20160281482A1 (en) 2008-10-13 2016-03-30 Circulated heated transfer fluid heating of subsurface hydrocarbon formations

Publications (1)

Publication Number Publication Date
US20100101783A1 true US20100101783A1 (en) 2010-04-29

Family

ID=42097829

Family Applications (14)

Application Number Title Priority Date Filing Date
US12/576,782 Expired - Fee Related US8353347B2 (en) 2008-10-13 2009-10-09 Deployment of insulated conductors for treating subsurface formations
US12/576,845 Abandoned US20100155070A1 (en) 2008-10-13 2009-10-09 Organonitrogen compounds used in treating hydrocarbon containing formations
US12/576,800 Expired - Fee Related US8261832B2 (en) 2008-10-13 2009-10-09 Heating subsurface formations with fluids
US12/576,697 Expired - Fee Related US8281861B2 (en) 2008-10-13 2009-10-09 Circulated heated transfer fluid heating of subsurface hydrocarbon formations
US12/576,722 Abandoned US20100101783A1 (en) 2008-10-13 2009-10-09 Using self-regulating nuclear reactors in treating a subsurface formation
US12/576,815 Expired - Fee Related US9051829B2 (en) 2008-10-13 2009-10-09 Perforated electrical conductors for treating subsurface formations
US12/576,763 Expired - Fee Related US8256512B2 (en) 2008-10-13 2009-10-09 Movable heaters for treating subsurface hydrocarbon containing formations
US12/576,825 Active 2031-09-06 US8881806B2 (en) 2008-10-13 2009-10-09 Systems and methods for treating a subsurface formation with electrical conductors
US12/576,732 Expired - Fee Related US8220539B2 (en) 2008-10-13 2009-10-09 Controlling hydrogen pressure in self-regulating nuclear reactors used to treat a subsurface formation
US12/576,790 Expired - Fee Related US8267170B2 (en) 2008-10-13 2009-10-09 Offset barrier wells in subsurface formations
US12/576,772 Expired - Fee Related US9022118B2 (en) 2008-10-13 2009-10-09 Double insulated heaters for treating subsurface formations
US12/576,751 Expired - Fee Related US9129728B2 (en) 2008-10-13 2009-10-09 Systems and methods of forming subsurface wellbores
US12/576,707 Expired - Fee Related US8267185B2 (en) 2008-10-13 2009-10-09 Circulated heated transfer fluid systems used to treat a subsurface formation
US15/085,561 Abandoned US20160281482A1 (en) 2008-10-13 2016-03-30 Circulated heated transfer fluid heating of subsurface hydrocarbon formations

Family Applications Before (4)

Application Number Title Priority Date Filing Date
US12/576,782 Expired - Fee Related US8353347B2 (en) 2008-10-13 2009-10-09 Deployment of insulated conductors for treating subsurface formations
US12/576,845 Abandoned US20100155070A1 (en) 2008-10-13 2009-10-09 Organonitrogen compounds used in treating hydrocarbon containing formations
US12/576,800 Expired - Fee Related US8261832B2 (en) 2008-10-13 2009-10-09 Heating subsurface formations with fluids
US12/576,697 Expired - Fee Related US8281861B2 (en) 2008-10-13 2009-10-09 Circulated heated transfer fluid heating of subsurface hydrocarbon formations

Family Applications After (9)

Application Number Title Priority Date Filing Date
US12/576,815 Expired - Fee Related US9051829B2 (en) 2008-10-13 2009-10-09 Perforated electrical conductors for treating subsurface formations
US12/576,763 Expired - Fee Related US8256512B2 (en) 2008-10-13 2009-10-09 Movable heaters for treating subsurface hydrocarbon containing formations
US12/576,825 Active 2031-09-06 US8881806B2 (en) 2008-10-13 2009-10-09 Systems and methods for treating a subsurface formation with electrical conductors
US12/576,732 Expired - Fee Related US8220539B2 (en) 2008-10-13 2009-10-09 Controlling hydrogen pressure in self-regulating nuclear reactors used to treat a subsurface formation
US12/576,790 Expired - Fee Related US8267170B2 (en) 2008-10-13 2009-10-09 Offset barrier wells in subsurface formations
US12/576,772 Expired - Fee Related US9022118B2 (en) 2008-10-13 2009-10-09 Double insulated heaters for treating subsurface formations
US12/576,751 Expired - Fee Related US9129728B2 (en) 2008-10-13 2009-10-09 Systems and methods of forming subsurface wellbores
US12/576,707 Expired - Fee Related US8267185B2 (en) 2008-10-13 2009-10-09 Circulated heated transfer fluid systems used to treat a subsurface formation
US15/085,561 Abandoned US20160281482A1 (en) 2008-10-13 2016-03-30 Circulated heated transfer fluid heating of subsurface hydrocarbon formations

Country Status (10)

Country Link
US (14) US8353347B2 (ru)
EP (6) EP2334894A1 (ru)
JP (6) JP2012508838A (ru)
CN (5) CN102187053A (ru)
AU (6) AU2009303606B2 (ru)
BR (2) BRPI0920141A2 (ru)
CA (6) CA2739039C (ru)
IL (5) IL211951A (ru)
RU (6) RU2529537C2 (ru)
WO (7) WO2010045097A1 (ru)

Cited By (36)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US20080184587A1 (en) * 2007-02-02 2008-08-07 Shivvers Steve D High efficiency drier with multi stage heating and drying zones
US20100101794A1 (en) * 2008-10-13 2010-04-29 Robert Charles Ryan Heating subsurface formations with fluids
US7866385B2 (en) 2006-04-21 2011-01-11 Shell Oil Company Power systems utilizing the heat of produced formation fluid
US7942203B2 (en) 2003-04-24 2011-05-17 Shell Oil Company Thermal processes for subsurface formations
US7987613B2 (en) * 2004-10-12 2011-08-02 Great River Energy Control system for particulate material drying apparatus and process
US8151907B2 (en) 2008-04-18 2012-04-10 Shell Oil Company Dual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations
US8196658B2 (en) 2007-10-19 2012-06-12 Shell Oil Company Irregular spacing of heat sources for treating hydrocarbon containing formations
US8225866B2 (en) 2000-04-24 2012-07-24 Shell Oil Company In situ recovery from a hydrocarbon containing formation
US8230927B2 (en) 2005-04-22 2012-07-31 Shell Oil Company Methods and systems for producing fluid from an in situ conversion process
US8257112B2 (en) 2009-10-09 2012-09-04 Shell Oil Company Press-fit coupling joint for joining insulated conductors
US20120286054A1 (en) * 2009-10-07 2012-11-15 Mark Collins Apparatus for generating heat
US8327932B2 (en) 2009-04-10 2012-12-11 Shell Oil Company Recovering energy from a subsurface formation
US8356935B2 (en) 2009-10-09 2013-01-22 Shell Oil Company Methods for assessing a temperature in a subsurface formation
WO2013012822A1 (en) * 2011-07-15 2013-01-24 Cardinal Health 414, Llc Systems, methods, and devices for producing, manufacturing, and control of radiopharmaceuticals
US20130067762A1 (en) * 2006-10-04 2013-03-21 Varco I/P, Inc. Reclamation of components of wellbore cuttings material
US8485256B2 (en) 2010-04-09 2013-07-16 Shell Oil Company Variable thickness insulated conductors
US20130301767A1 (en) * 2012-05-11 2013-11-14 Ge-Hitachi Nuclear Energy Americas, Llc System and method for a commercial spent nuclear fuel repository turning heat and gamma radiation into value
US8586866B2 (en) 2010-10-08 2013-11-19 Shell Oil Company Hydroformed splice for insulated conductors
US8631866B2 (en) 2010-04-09 2014-01-21 Shell Oil Company Leak detection in circulated fluid systems for heating subsurface formations
US8701768B2 (en) 2010-04-09 2014-04-22 Shell Oil Company Methods for treating hydrocarbon formations
US8820406B2 (en) 2010-04-09 2014-09-02 Shell Oil Company Electrodes for electrical current flow heating of subsurface formations with conductive material in wellbore
US8857051B2 (en) 2010-10-08 2014-10-14 Shell Oil Company System and method for coupling lead-in conductor to insulated conductor
US8939207B2 (en) 2010-04-09 2015-01-27 Shell Oil Company Insulated conductor heaters with semiconductor layers
US8943686B2 (en) 2010-10-08 2015-02-03 Shell Oil Company Compaction of electrical insulation for joining insulated conductors
US9016370B2 (en) 2011-04-08 2015-04-28 Shell Oil Company Partial solution mining of hydrocarbon containing layers prior to in situ heat treatment
US9033042B2 (en) 2010-04-09 2015-05-19 Shell Oil Company Forming bitumen barriers in subsurface hydrocarbon formations
US9139316B2 (en) 2010-12-29 2015-09-22 Cardinal Health 414, Llc Closed vial fill system for aseptic dispensing
US9309755B2 (en) 2011-10-07 2016-04-12 Shell Oil Company Thermal expansion accommodation for circulated fluid systems used to heat subsurface formations
US9417332B2 (en) 2011-07-15 2016-08-16 Cardinal Health 414, Llc Radiopharmaceutical CZT sensor and apparatus
US9466896B2 (en) 2009-10-09 2016-10-11 Shell Oil Company Parallelogram coupling joint for coupling insulated conductors
US9480962B2 (en) 2011-07-15 2016-11-01 Cardinal Health 414, Llc Modular cassette synthesis unit
US9605524B2 (en) 2012-01-23 2017-03-28 Genie Ip B.V. Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation
US9647194B1 (en) 2006-08-25 2017-05-09 Hypres, Inc. Superconductive multi-chip module for high speed digital circuits
US10047594B2 (en) 2012-01-23 2018-08-14 Genie Ip B.V. Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation
US11555473B2 (en) 2018-05-29 2023-01-17 Kontak LLC Dual bladder fuel tank
US11638331B2 (en) 2018-05-29 2023-04-25 Kontak LLC Multi-frequency controllers for inductive heating and associated systems and methods

Families Citing this family (203)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US7004247B2 (en) 2001-04-24 2006-02-28 Shell Oil Company Conductor-in-conduit heat sources for in situ thermal processing of an oil shale formation
NZ532091A (en) 2001-10-24 2005-12-23 Shell Int Research In situ recovery from a hydrocarbon containing formation using barriers
US8161998B2 (en) * 2007-06-04 2012-04-24 Matos Jeffrey A Frozen/chilled fluid for pipelines and for storage facilities
CA2579496A1 (en) 2004-04-23 2005-11-03 Shell Internationale Research Maatschappij B.V. Subsurface electrical heaters using nitride insulation
JP5330999B2 (ja) 2006-10-20 2013-10-30 シエル・インターナシヨネイル・リサーチ・マーチヤツピイ・ベー・ウイ 流体によるタールサンド地層の複数部分中での炭化水素の移動
AU2009201961B2 (en) * 2007-02-12 2011-04-14 Valkyrie Commissioning Services, Inc Apparatus and methods for subsea control system testing
WO2008131171A1 (en) 2007-04-20 2008-10-30 Shell Oil Company Parallel heater system for subsurface formations
JP5063195B2 (ja) * 2007-05-31 2012-10-31 ラピスセミコンダクタ株式会社 データ処理装置
US9188086B2 (en) 2008-01-07 2015-11-17 Mcalister Technologies, Llc Coupled thermochemical reactors and engines, and associated systems and methods
US8318131B2 (en) 2008-01-07 2012-11-27 Mcalister Technologies, Llc Chemical processes and reactors for efficiently producing hydrogen fuels and structural materials, and associated systems and methods
AT10660U1 (de) * 2008-03-19 2009-07-15 Binder Co Ag Trockner mit kühlmedium
US20110203776A1 (en) * 2009-02-17 2011-08-25 Mcalister Technologies, Llc Thermal transfer device and associated systems and methods
US8441361B2 (en) 2010-02-13 2013-05-14 Mcallister Technologies, Llc Methods and apparatuses for detection of properties of fluid conveyance systems
US7792250B1 (en) * 2009-04-30 2010-09-07 Halliburton Energy Services Inc. Method of selecting a wellbore cement having desirable characteristics
CN102612640B (zh) * 2009-10-09 2014-01-08 国际壳牌研究有限公司 用于估定地下地层中温度的方法
US9310245B2 (en) * 2009-10-28 2016-04-12 Csir Integrated sensing device for assessing integrity of a rock mass and corresponding method
US8386221B2 (en) * 2009-12-07 2013-02-26 Nuovo Pignone S.P.A. Method for subsea equipment subject to hydrogen induced stress cracking
US8602658B2 (en) * 2010-02-05 2013-12-10 Baker Hughes Incorporated Spoolable signal conduction and connection line and method
KR20130036001A (ko) 2010-02-13 2013-04-09 맥알리스터 테크놀로지즈 엘엘씨 수소계 연료 및 구조적 요소를 생성하기 위한 투과 표면을 갖춘 반응기 용기와, 관련 시스템 및 방법
AU2011216249A1 (en) * 2010-02-13 2012-09-06 Mcalister Technologies, Llc Chemical reactors with re-radiating surfaces and associated systems and methods
US8397828B2 (en) * 2010-03-25 2013-03-19 Baker Hughes Incorporated Spoolable downhole control system and method
US20110277992A1 (en) * 2010-05-14 2011-11-17 Paul Grimes Systems and methods for enhanced recovery of hydrocarbonaceous fluids
CN105588236B (zh) 2010-05-25 2019-07-09 7Ac技术公司 使用液体干燥剂进行空气调节及其它处理的方法和系统
WO2012048196A1 (en) * 2010-10-08 2012-04-12 Shell Oil Company Methods of heating a subsurface formation using electrically conductive particles
CA2813044C (en) * 2010-10-08 2020-01-14 Charles D'angelo Methods for joining insulated conductors
US20130251547A1 (en) * 2010-12-28 2013-09-26 Hansen Energy Solutions Llc Liquid Lift Pumps for Gas Wells
US20120228286A1 (en) * 2011-03-09 2012-09-13 Central Garden And Pet Company Inductive Heating Device for Aquarium Tanks
JP5399436B2 (ja) * 2011-03-30 2014-01-29 公益財団法人地球環境産業技術研究機構 貯留物質の貯留装置および貯留方法
WO2012154343A1 (en) * 2011-04-08 2012-11-15 Shell Oil Company Compaction of electrical insulation for joining insulated conductors
RU2587459C2 (ru) 2011-04-08 2016-06-20 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Системы для соединения изолированных проводников
CN102200004A (zh) * 2011-05-12 2011-09-28 刘锋 游梁式抽油机专用节能配套装置及其抽油机
US8978769B2 (en) * 2011-05-12 2015-03-17 Richard John Moore Offshore hydrocarbon cooling system
US8887806B2 (en) 2011-05-26 2014-11-18 Halliburton Energy Services, Inc. Method for quantifying cement blend components
JP6230533B2 (ja) 2011-07-25 2017-11-15 エイチ２ カタリスト、エルエルシー 水素を生成するための方法およびシステム
WO2013025659A1 (en) 2011-08-12 2013-02-21 Mcalister Technologies, Llc Reducing and/or harvesting drag energy from transport vehicles, includings for chemical reactors, and associated systems and methods
WO2013025640A2 (en) * 2011-08-12 2013-02-21 Mcalister Technologies, Llc Geothermal energization of a non-combustion chemical reactor and associated systems and methods
US8673509B2 (en) 2011-08-12 2014-03-18 Mcalister Technologies, Llc Fuel-cell systems operable in multiple modes for variable processing of feedstock materials and associated devices, systems, and methods
WO2013025655A2 (en) 2011-08-12 2013-02-21 Mcalister Technologies, Llc Systems and methods for providing supplemental aqueous thermal energy
US8888408B2 (en) 2011-08-12 2014-11-18 Mcalister Technologies, Llc Systems and methods for collecting and processing permafrost gases, and for cooling permafrost
US9302681B2 (en) 2011-08-12 2016-04-05 Mcalister Technologies, Llc Mobile transport platforms for producing hydrogen and structural materials, and associated systems and methods
US8826657B2 (en) 2011-08-12 2014-09-09 Mcallister Technologies, Llc Systems and methods for providing supplemental aqueous thermal energy
CN103857873A (zh) 2011-08-12 2014-06-11 麦卡利斯特技术有限责任公司 从水下来源除去和处理气体的系统和方法
US8669014B2 (en) 2011-08-12 2014-03-11 Mcalister Technologies, Llc Fuel-cell systems operable in multiple modes for variable processing of feedstock materials and associated devices, systems, and methods
US8734546B2 (en) 2011-08-12 2014-05-27 Mcalister Technologies, Llc Geothermal energization of a non-combustion chemical reactor and associated systems and methods
US8911703B2 (en) 2011-08-12 2014-12-16 Mcalister Technologies, Llc Reducing and/or harvesting drag energy from transport vehicles, including for chemical reactors, and associated systems and methods
JO3139B1 (ar) 2011-10-07 2017-09-20 Shell Int Research تشكيل موصلات معزولة باستخدام خطوة اختزال أخيرة بعد المعالجة الحرارية.
JO3141B1 (ar) 2011-10-07 2017-09-20 Shell Int Research الوصلات المتكاملة للموصلات المعزولة
CN104011327B (zh) * 2011-10-07 2016-12-14 国际壳牌研究有限公司 利用地下地层中的绝缘导线的介电性能来确定绝缘导线的性能
US9243482B2 (en) 2011-11-01 2016-01-26 Nem Energy B.V. Steam supply for enhanced oil recovery
CN104066927A (zh) 2011-11-07 2014-09-24 安赛科公司 压力释放装置、系统和方法
CN102436856A (zh) * 2011-12-13 2012-05-02 匡仲平 核泄漏事故引发的核辐射污染规避方法
RU2485300C1 (ru) * 2011-12-14 2013-06-20 Открытое акционерное общество "Татнефть" имени В.Д. Шашина Способ разработки залежи нефти в трещиноватых коллекторах
EP2610570B1 (en) * 2011-12-29 2016-11-23 Ipsen, Inc. Heating element arrangement for a vacuum heat treating furnace
EP2612983B1 (en) * 2012-01-03 2014-05-21 Quantum Technologie GmbH Apparatus and method for oil sand exploitation
US20150203776A1 (en) * 2012-02-18 2015-07-23 Genie Ip B.V. Method and system for heating a bed of hydrocarbon- containing rocks
CA2811666C (en) 2012-04-05 2021-06-29 Shell Internationale Research Maatschappij B.V. Compaction of electrical insulation for joining insulated conductors
US9303487B2 (en) * 2012-04-30 2016-04-05 Baker Hughes Incorporated Heat treatment for removal of bauschinger effect or to accelerate cement curing
NO2844830T3 (ru) * 2012-05-04 2018-05-19
US9447674B2 (en) * 2012-05-16 2016-09-20 Chevron U.S.A. Inc. In-situ method and system for removing heavy metals from produced fluids
CA2872792C (en) * 2012-05-16 2020-08-25 Chevron U.S.A. Inc. Process, method, and system for removing mercury from fluids
JP2013249605A (ja) * 2012-05-31 2013-12-12 Ihi Corp ガスハイドレート回収装置
KR102189997B1 (ko) * 2012-06-11 2020-12-11 7에이씨 테크놀로지스, 아이엔씨. 난류형 내식성 열 교환기들을 위한 방법들 및 시스템들
US10076001B2 (en) * 2012-07-05 2018-09-11 Nvent Services Gmbh Mineral insulated cable having reduced sheath temperature
US9896918B2 (en) 2012-07-27 2018-02-20 Mbl Water Partners, Llc Use of ionized water in hydraulic fracturing
US8424784B1 (en) 2012-07-27 2013-04-23 MBJ Water Partners Fracture water treatment method and system
WO2014028522A1 (en) * 2012-08-13 2014-02-20 Chevron U.S.A. Inc. Initiating production of clathrates by use of thermosyphons
EP2898180B1 (en) * 2012-09-20 2018-01-10 Pentair Thermal Management LLC Downhole wellbore heating system and method
WO2014058777A1 (en) 2012-10-09 2014-04-17 Shell Oil Company Method for heating a subterranean formation penetrated by a wellbore
US20150260023A1 (en) * 2012-10-16 2015-09-17 Genie Ip B.V. System and method for thermally treating a subsurface formation by a heated molten salt mixture
US10443315B2 (en) * 2012-11-28 2019-10-15 Nextstream Wired Pipe, Llc Transmission line for wired pipe
EP2929256A4 (en) 2012-12-04 2016-08-03 7Ac Technologies Inc METHODS AND SYSTEMS FOR COOLING BUILDINGS WITH HIGH THERMAL LOADS THROUGH DESICCANT COOLERS
RU2549654C2 (ru) * 2012-12-04 2015-04-27 Общество с ограниченной ответственностью "Краснодарский Компрессорный Завод" Азотная компрессорная станция для повышения нефтеотдачи пластов (варианты)
RU2015126797A (ru) 2012-12-06 2017-01-12 Сименс Акциенгезелльшафт Система и способ введения тепла в геологическую формацию при помощи электромагнитной индукции
GB201223055D0 (en) * 2012-12-20 2013-02-06 Carragher Paul Method and apparatus for use in well abandonment
KR20200009148A (ko) 2013-03-01 2020-01-29 7에이씨 테크놀로지스, 아이엔씨. 흡습제 공기 조화 방법 및 시스템
US20140251596A1 (en) * 2013-03-05 2014-09-11 Cenovus Energy Inc. Single vertical or inclined well thermal recovery process
US20140251608A1 (en) * 2013-03-05 2014-09-11 Cenovus Energy Inc. Single vertical or inclined well thermal recovery process
EP2972009B1 (en) 2013-03-14 2019-09-18 7AC Technologies, Inc. Split liquid desiccant air conditioning system
US9709285B2 (en) 2013-03-14 2017-07-18 7Ac Technologies, Inc. Methods and systems for liquid desiccant air conditioning system retrofit
WO2014160301A1 (en) 2013-03-14 2014-10-02 Mcalister Technologies, Llc Method and apparatus for generating hydrogen from metal
US10316644B2 (en) 2013-04-04 2019-06-11 Shell Oil Company Temperature assessment using dielectric properties of an insulated conductor heater with selected electrical insulation
DE102013104643B3 (de) * 2013-05-06 2014-06-18 Borgwarner Beru Systems Gmbh Korona-Zündeinrichtung
WO2014189491A1 (en) * 2013-05-21 2014-11-27 Halliburton Energy Serviices, Inc. High-voltage drilling methods and systems using hybrid drillstring conveyance
EP3667191B1 (en) 2013-06-12 2024-05-29 Copeland LP Liquid desiccant air conditioning system and method of dehumidifying and cooling an air stream in a building
US9382785B2 (en) 2013-06-17 2016-07-05 Baker Hughes Incorporated Shaped memory devices and method for using same in wellbores
US9701892B2 (en) 2014-04-17 2017-07-11 Baker Hughes Incorporated Method of pumping aqueous fluid containing surface modifying treatment agent into a well
US9822621B2 (en) 2013-09-20 2017-11-21 Baker Hughes, A Ge Company, Llc Method of using surface modifying treatment agents to treat subterranean formations
NZ717494A (en) 2013-09-20 2020-07-31 Baker Hughes Inc Method of inhibiting fouling on a metallic surface using a surface modifying treatment agent
NZ716773A (en) 2013-09-20 2020-06-26 Baker Hughes Inc Composites for use in stimulation and sand control operations
WO2015042489A1 (en) 2013-09-20 2015-03-26 Baker Hughes Incorporated Method of using surface modifying metallic treatment agents to treat subterranean formations
MX2016002653A (es) 2013-09-20 2016-06-06 Baker Hughes Inc Materiales compuestos que contienen organofosforo para el uso en operaciones de tratamiento de pozo.
DE102013018210A1 (de) * 2013-10-30 2015-04-30 Linde Aktiengesellschaft Verfahren zur Erzeugung eines zusammenhängenden Eiskörpers bei einer Bodenvereisung
WO2015102578A1 (en) * 2013-12-30 2015-07-09 Halliburton Energy Services, Inc. Ranging using current profiling
CA2877367C (en) * 2014-01-13 2020-12-22 Conocophillips Company Anti-retention agent in steam-solvent oil recovery
GB2535927B (en) * 2014-01-24 2020-09-16 Halliburton Energy Services Inc Method and criteria for trajectory control
CA3176275A1 (en) 2014-02-18 2015-08-18 Athabasca Oil Corporation Cable-based well heater
MX2016011519A (es) * 2014-03-07 2017-01-09 Greenfire Energy Inc Proceso y metodo para producir energia geotermica.
US9637996B2 (en) 2014-03-18 2017-05-02 Baker Hughes Incorporated Downhole uses of nanospring filled elastomers
US10323867B2 (en) 2014-03-20 2019-06-18 7Ac Technologies, Inc. Rooftop liquid desiccant systems and methods
US9618435B2 (en) * 2014-03-31 2017-04-11 Dmar Engineering, Inc. Umbilical bend-testing
JP2017512930A (ja) 2014-04-04 2017-05-25 シエル・インターナシヨナル・リサーチ・マートスハツペイ・ベー・ヴエー 熱処理後の最終圧延ステップを使用して形成された絶縁導体
CA2952871C (en) 2014-06-19 2023-04-04 Evolution Engineering Inc. Downhole system with integrated backup sensors
GB2527847A (en) * 2014-07-04 2016-01-06 Compactgtl Ltd Catalytic reactors
RU2559250C1 (ru) * 2014-08-01 2015-08-10 Олег Васильевич Коломийченко Забойная каталитическая сборка для теплового воздействия на пласты, содержащие углеводороды и твердые органические вещества
US9451792B1 (en) * 2014-09-05 2016-09-27 Atmos Nation, LLC Systems and methods for vaporizing assembly
US9939421B2 (en) * 2014-09-10 2018-04-10 Saudi Arabian Oil Company Evaluating effectiveness of ceramic materials for hydrocarbons recovery
WO2016044549A1 (en) 2014-09-17 2016-03-24 Garrison Dental Solutions, Llc Dental curing light
RU2569375C1 (ru) * 2014-10-21 2015-11-27 Николай Борисович Болотин Способ и устройство для подогрева продуктивного нефтесодержащего пласта
DE102014223621A1 (de) * 2014-11-19 2016-05-19 Siemens Aktiengesellschaft Lagerstättenheizung
JP6718871B2 (ja) 2014-11-21 2020-07-08 ７エーシー テクノロジーズ，インコーポレイテッド 液体乾燥剤空調システム
AR103391A1 (es) 2015-01-13 2017-05-03 Bp Corp North America Inc Métodos y sistemas para producir hidrocarburos desde roca productora de hidrocarburos a través del tratamiento combinado de la roca y la inyección de agua posterior
RU2591860C1 (ru) * 2015-02-05 2016-07-20 Федеральное государственное бюджетное образовательное учреждение высшего профессионального образования "Южно-Уральский государственный университет" (национальный исследовательский университет) (ФГБОУ ВПО "ЮУрГУ" (НИУ)) Способ извлечения тяжелой нефти из продуктивного пласта и устройство для его осуществления
FR3032564B1 (fr) * 2015-02-11 2017-03-03 Saipem Sa Procede de raccordement de cables d'une section unitaire de conduite destinee a etre assemblee verticalement sur une conduite sous-marine de transport de fluides
CA3212909A1 (en) 2015-04-03 2016-10-06 Rama Rau YELUNDUR Apparatus and method of focused in-situ electrical heating of hydrocarbon bearing formations
US10280747B2 (en) * 2015-05-20 2019-05-07 Saudi Arabian Oil Company Sampling techniques to detect hydrocarbon seepage
GB2539045A (en) * 2015-06-05 2016-12-07 Statoil Asa Subsurface heater configuration for in situ hydrocarbon production
WO2017040753A1 (en) * 2015-09-01 2017-03-09 Exotex, Inc. Construction products and systems for providing geothermal heat
US9556719B1 (en) 2015-09-10 2017-01-31 Don P. Griffin Methods for recovering hydrocarbons from shale using thermally-induced microfractures
EP3371492B1 (en) 2015-11-06 2021-07-07 Oklahoma Safety Equipment Company, Inc. Rupture disc device and method of assembly thereof
US10304591B1 (en) * 2015-11-18 2019-05-28 Real Power Licensing Corp. Reel cooling method
CA3007623A1 (en) 2015-12-09 2017-06-15 Truva Corporation Environment-aware cross-layer communication protocol in underground oil reservoirs
CN106917616B (zh) * 2015-12-28 2019-11-08 中国石油天然气股份有限公司 稠油油藏的预热装置及方法
GB2547672B (en) * 2016-02-25 2018-02-21 Rejuvetech Ltd System and method
US10067201B2 (en) * 2016-04-14 2018-09-04 Texas Instruments Incorporated Wiring layout to reduce magnetic field
WO2017189397A1 (en) 2016-04-26 2017-11-02 Shell Oil Company Roller injector for deploying insulated conductor heaters
GB2550849B (en) * 2016-05-23 2020-06-17 Equinor Energy As Interface and integration method for external control of the drilling control system
US10125588B2 (en) * 2016-06-30 2018-11-13 Must Holding Llc Systems and methods for recovering bitumen from subterranean formations
NO343262B1 (en) * 2016-07-22 2019-01-14 Norges Miljoe Og Biovitenskapelige Univ Nmbu Solar thermal collecting and storage
CN106292277B (zh) * 2016-08-15 2020-01-07 上海交通大学 基于全局滑模控制的亚临界火电机组协调控制方法
CN106168119B (zh) * 2016-08-15 2018-07-13 中国石油天然气股份有限公司 井下电加热水平生产井管柱结构
WO2018067715A1 (en) 2016-10-06 2018-04-12 Shell Oil Company High voltage, low current mineral insulated cable heater
WO2018067713A1 (en) 2016-10-06 2018-04-12 Shell Oil Company Subsurface electrical connections for high voltage, low current mineral insulated cable heaters
CN106595113A (zh) * 2016-12-12 2017-04-26 吉林省联冠石油科技有限公司 超导加温换热装置及换热方法
EP3337290B1 (en) * 2016-12-13 2019-11-27 Nexans Subsea direct electric heating system
EP3577200A2 (en) * 2017-01-31 2019-12-11 Saudi Arabian Oil Company In-situ hic growth monitoring probe
US10041163B1 (en) 2017-02-03 2018-08-07 Ge-Hitachi Nuclear Energy Americas Llc Plasma spray coating for sealing a defect area in a workpiece
US20180292133A1 (en) * 2017-04-05 2018-10-11 Rex Materials Group Heat treating furnace
EP3389088A1 (en) * 2017-04-12 2018-10-17 ABB Schweiz AG Heat exchanging arrangement and subsea electronic system
CN107387180B (zh) * 2017-07-17 2019-08-20 浙江陆特能源科技股份有限公司 地层煤就地化浆供热系统及地层煤就地化浆发电供热的方法
US10724341B2 (en) 2017-08-14 2020-07-28 Schlumberger Technology Corporation Electrical power transmission for well construction apparatus
US10649427B2 (en) 2017-08-14 2020-05-12 Schlumberger Technology Corporation Electrical power transmission for well construction apparatus
US10699822B2 (en) 2017-08-14 2020-06-30 Schlumberger Technology Corporation Electrical power transmission for well construction apparatus
US10745975B2 (en) 2017-08-14 2020-08-18 Schlumberger Technology Corporation Electrical power transmission for well construction apparatus
US10760348B2 (en) 2017-08-14 2020-09-01 Schlumberger Technology Corporation Electrical power transmission for well construction apparatus
US10697275B2 (en) 2017-08-14 2020-06-30 Schlumberger Technology Corporation Electrical power transmission for well construction apparatus
RU2652909C1 (ru) * 2017-08-28 2018-05-03 Общество с ограниченной ответственностью "Научно-техническая и торгово-промышленная фирма "ТЕХНОПОДЗЕМЭНЕРГО" (ООО "Техноподземэнерго") Шахтно-скважинный газотурбинно-атомный нефтегазодобывающий комплекс (комбинат)
US10662709B2 (en) 2017-09-06 2020-05-26 Schlumberger Technology Corporation Local electrical room module for well construction apparatus
US10655292B2 (en) 2017-09-06 2020-05-19 Schlumberger Technology Corporation Local electrical room module for well construction apparatus
US10472953B2 (en) 2017-09-06 2019-11-12 Schlumberger Technology Corporation Local electrical room module for well construction apparatus
WO2019053550A1 (en) * 2017-09-12 2019-03-21 Politecnico Di Milano CO2 MIXTURES USED AS WORKING FLUID IN THERMODYNAMIC CYCLES
CA3075856A1 (en) 2017-09-13 2019-03-21 Chevron Phillips Chemical Company Lp Pvdf pipe and methods of making and using same
US10704371B2 (en) * 2017-10-13 2020-07-07 Chevron U.S.A. Inc. Low dielectric zone for hydrocarbon recovery by dielectric heating
EP3704416B1 (en) 2017-11-01 2023-04-12 Emerson Climate Technologies, Inc. Methods and apparatus for uniform distribution of liquid desiccant in membrane modules in liquid desiccant air-conditioning systems
EP3704415A4 (en) 2017-11-01 2021-11-03 7AC Technologies, Inc. TANK SYSTEM FOR AN AIR CONDITIONING SYSTEM WITH LIQUID DRYING AGENTS
JP2021502527A (ja) * 2017-11-06 2021-01-28 コンセプト グループ エルエルシー 断熱モジュールおよび関連方法
JP7220213B2 (ja) * 2017-11-13 2023-02-09 エセックス フルカワ マグネット ワイヤ ユーエスエイ エルエルシー 内部空洞を有する巻線物品
US11274856B2 (en) * 2017-11-16 2022-03-15 Ari Peter Berman Method of deploying a heat exchanger pipe
RU2669647C1 (ru) * 2017-11-29 2018-10-12 Публичное акционерное общество "Татнефть" имени В.Д. Шашина Способ разработки залежи высоковязкой и сверхвязкой нефти тепловыми методами на поздней стадии разработки
US10399895B2 (en) * 2017-12-13 2019-09-03 Pike Technologies Of Wisconsin, Inc. Bismuth-indium alloy for liquid-tight bonding of optical windows
US10201042B1 (en) * 2018-01-19 2019-02-05 Trs Group, Inc. Flexible helical heater
CN107991158B (zh) * 2018-01-29 2021-11-12 山东交通学院 可控击实温度的沥青混合料马歇尔击实仪及试验方法
US10822942B2 (en) * 2018-02-13 2020-11-03 Baker Hughes, A Ge Company, Llc Telemetry system including a super conductor for a resource exploration and recovery system
WO2019164467A2 (en) * 2018-02-21 2019-08-29 Me Well Services Petrol Ve Saha Hizmetleri San. Tic. Ltd. Sti. A gas injection system
US10137486B1 (en) * 2018-02-27 2018-11-27 Chevron U.S.A. Inc. Systems and methods for thermal treatment of contaminated material
US11149538B2 (en) * 2018-03-01 2021-10-19 Baker Hughes, A Ge Company, Llc Systems and methods for determining bending of a drilling tool, the drilling tool having electrical conduit
US10837248B2 (en) 2018-04-25 2020-11-17 Skye Buck Technology, LLC. Method and apparatus for a chemical capsule joint
US11022330B2 (en) 2018-05-18 2021-06-01 Emerson Climate Technologies, Inc. Three-way heat exchangers for liquid desiccant air-conditioning systems and methods of manufacture
US11053775B2 (en) * 2018-11-16 2021-07-06 Leonid Kovalev Downhole induction heater
CN109779625B (zh) * 2019-01-25 2022-09-09 华北科技学院 一种基于钻孔煤屑尺寸分布状况的突出预测方法与装置
CN112180815A (zh) * 2019-07-01 2021-01-05 苏州五蕴明泰科技有限公司 控制废弃物燃烧过程中二氧化碳排放量的方法
WO2021026432A1 (en) 2019-08-07 2021-02-11 Saudi Arabian Oil Company Determination of geologic permeability correlative with magnetic permeability measured in-situ
CN110705110B (zh) * 2019-10-09 2023-04-14 浙江强盛压缩机制造有限公司 大型往复压缩机高压填料盒的应力和应变计算方法
CN110954676B (zh) * 2019-12-03 2021-06-29 同济大学 用于模拟盾构下穿既有隧道施工可视化试验装置
US11559847B2 (en) 2020-01-08 2023-01-24 General Electric Company Superalloy part and method of processing
US11979950B2 (en) 2020-02-18 2024-05-07 Trs Group, Inc. Heater for contaminant remediation
CN111271038A (zh) * 2020-03-12 2020-06-12 内蒙古科技大学 一种低渗透性煤体的新型煤层气增产方法
US10912154B1 (en) * 2020-08-06 2021-02-02 Michael E. Brown Concrete heating system
CN112096294A (zh) * 2020-09-13 2020-12-18 江苏刘一刀精密机械有限公司 一种高导向性新型金刚石钻头
CN112252121B (zh) * 2020-11-11 2021-11-16 浙江八咏新型材料有限责任公司 一种市政道路施工用沥青加热熔融装置
US11851996B2 (en) 2020-12-18 2023-12-26 Jack McIntyre Oil production system and method
CN112324409B (zh) * 2020-12-31 2021-07-06 西南石油大学 一种在油层中原位产生溶剂开采稠油的方法
RU2753290C1 (ru) * 2021-02-10 2021-08-12 Общество с ограниченной ответственностью «АСДМ-Инжиниринг» Способ и система для борьбы с асфальтосмолопарафиновыми и/или газогидратными отложениями в нефтегазовых скважинах
US11642709B1 (en) 2021-03-04 2023-05-09 Trs Group, Inc. Optimized flux ERH electrode
RU2756152C1 (ru) * 2021-03-04 2021-09-28 Акционерное общество «Зарубежнефть» Внутрискважинный пучковый нагреватель
RU2756155C1 (ru) * 2021-03-04 2021-09-28 Акционерное общество «Зарубежнефть» Внутрискважинный кольцевой нагреватель
US11214450B1 (en) * 2021-03-11 2022-01-04 Cciip Llc Method of proofing an innerduct/microduct and proofing manifold
CN113051725B (zh) * 2021-03-12 2022-09-09 哈尔滨工程大学 基于通用型辅助变量法的det与relap5耦合的动态特性分析方法
GB202104638D0 (en) * 2021-03-31 2021-05-12 Head Philip Bismuth metal to metal encapsulated electrical power cable system for ESP
US11713651B2 (en) * 2021-05-11 2023-08-01 Saudi Arabian Oil Company Heating a formation of the earth while drilling a wellbore
US11619097B2 (en) 2021-05-24 2023-04-04 Saudi Arabian Oil Company System and method for laser downhole extended sensing
US11725504B2 (en) 2021-05-24 2023-08-15 Saudi Arabian Oil Company Contactless real-time 3D mapping of surface equipment
CN113153250B (zh) * 2021-06-11 2021-11-19 盐城瑞德石化机械有限公司 一种设有限位机构的稳定型井下配注器
CN113266327A (zh) * 2021-07-05 2021-08-17 西南石油大学 一种油气井下多功能涡流加热装置与方法
US11879328B2 (en) 2021-08-05 2024-01-23 Saudi Arabian Oil Company Semi-permanent downhole sensor tool
US20230130169A1 (en) * 2021-10-26 2023-04-27 Jack McIntyre Fracturing Hot Rock
US11860077B2 (en) 2021-12-14 2024-01-02 Saudi Arabian Oil Company Fluid flow sensor using driver and reference electromechanical resonators
CN114300213B (zh) * 2022-01-24 2024-01-26 中国科学院电工研究所 一种高热导铌三锡超导线圈及其制作方法
CN114508336B (zh) * 2022-01-30 2022-09-30 中国矿业大学 一种用于松软煤层的钻孔、解卡和致裂一体装置及方法
US11867049B1 (en) 2022-07-19 2024-01-09 Saudi Arabian Oil Company Downhole logging tool
CN115050529B (zh) * 2022-08-15 2022-10-21 中国工程物理研究院流体物理研究所 一种高安全性新型水电阻
CN115340241A (zh) * 2022-08-27 2022-11-15 辽宁大学 一种循环利用的矿井水处理装置
US11913329B1 (en) 2022-09-21 2024-02-27 Saudi Arabian Oil Company Untethered logging devices and related methods of logging a wellbore
WO2024112086A1 (ko) * 2022-11-22 2024-05-30 한국원자력연구원 미드룹 적용된 오일샌드 채굴용 경수형 원자로

Citations (99)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US48994A (en) * 1865-07-25 Improvement in devices for oil-wells
US94813A (en) * 1869-09-14 Improvement in torpedoes for oil-wells
US326439A (en) * 1885-09-15 Protecting wells
US760304A (en) * 1903-10-24 1904-05-17 Frank S Gilbert Heater for oil-wells.
US1342741A (en) * 1918-01-17 1920-06-08 David T Day Process for extracting oils and hydrocarbon material from shale and similar bituminous rocks
US1510655A (en) * 1922-11-21 1924-10-07 Clark Cornelius Process of subterranean distillation of volatile mineral substances
US1634236A (en) * 1925-03-10 1927-06-28 Standard Dev Co Method of and apparatus for recovering oil
US1666488A (en) * 1927-02-05 1928-04-17 Crawshaw Richard Apparatus for extracting oil from shale
US1681523A (en) * 1927-03-26 1928-08-21 Patrick V Downey Apparatus for heating oil wells
US1913395A (en) * 1929-11-14 1933-06-13 Lewis C Karrick Underground gasification of carbonaceous material-bearing substances
US2244256A (en) * 1939-12-16 1941-06-03 Electrical Treating Company Apparatus for clearing wells
US2365591A (en) * 1942-08-15 1944-12-19 Ranney Leo Method for producing oil from viscous deposits
US2423674A (en) * 1942-08-24 1947-07-08 Johnson & Co A Process of catalytic cracking of petroleum hydrocarbons
US2444755A (en) * 1946-01-04 1948-07-06 Ralph M Steffen Apparatus for oil sand heating
US2466945A (en) * 1946-02-21 1949-04-12 In Situ Gases Inc Generation of synthesis gas
US2472445A (en) * 1945-02-02 1949-06-07 Thermactor Company Apparatus for treating oil and gas bearing strata
US2484063A (en) * 1944-08-19 1949-10-11 Thermactor Corp Electric heater for subsurface materials
US2497868A (en) * 1946-10-10 1950-02-21 Dalin David Underground exploitation of fuel deposits
US2548360A (en) * 1948-03-29 1951-04-10 Stanley A Germain Electric oil well heater
US2593477A (en) * 1949-06-10 1952-04-22 Us Interior Process of underground gasification of coal
US2595979A (en) * 1949-01-25 1952-05-06 Texas Co Underground liquefaction of coal
US2630307A (en) * 1948-12-09 1953-03-03 Carbonic Products Inc Method of recovering oil from oil shale
US2630306A (en) * 1952-01-03 1953-03-03 Socony Vacuum Oil Co Inc Subterranean retorting of shales
US2634961A (en) * 1946-01-07 1953-04-14 Svensk Skifferolje Aktiebolage Method of electrothermal production of shale oil
US2642943A (en) * 1949-05-20 1953-06-23 Sinclair Oil & Gas Co Oil recovery process
US2670802A (en) * 1949-12-16 1954-03-02 Thermactor Company Reviving or increasing the production of clogged or congested oil wells
US2685930A (en) * 1948-08-12 1954-08-10 Union Oil Co Oil well production process
US2695163A (en) * 1950-12-09 1954-11-23 Stanolind Oil & Gas Co Method for gasification of subterranean carbonaceous deposits
US2703621A (en) * 1953-05-04 1955-03-08 George W Ford Oil well bottom hole flow increasing unit
US2714930A (en) * 1950-12-08 1955-08-09 Union Oil Co Apparatus for preventing paraffin deposition
US2732195A (en) * 1956-01-24 Ljungstrom
US2734579A (en) * 1956-02-14 Production from bituminous sands
US2771954A (en) * 1953-04-29 1956-11-27 Exxon Research Engineering Co Treatment of petroleum production wells
US2777679A (en) * 1952-03-07 1957-01-15 Svenska Skifferolje Ab Recovering sub-surface bituminous deposits by creating a frozen barrier and heating in situ
US2780449A (en) * 1952-12-26 1957-02-05 Sinclair Oil & Gas Co Thermal process for in-situ decomposition of oil shale
US2780450A (en) * 1952-03-07 1957-02-05 Svenska Skifferolje Ab Method of recovering oil and gases from non-consolidated bituminous geological formations by a heating treatment in situ
US2786660A (en) * 1948-01-05 1957-03-26 Phillips Petroleum Co Apparatus for gasifying coal
US2789805A (en) * 1952-05-27 1957-04-23 Svenska Skifferolje Ab Device for recovering fuel from subterraneous fuel-carrying deposits by heating in their natural location using a chain heat transfer member
US2793696A (en) * 1954-07-22 1957-05-28 Pan American Petroleum Corp Oil recovery by underground combustion
US2804149A (en) * 1956-12-12 1957-08-27 John R Donaldson Oil well heater and reviver
US2841375A (en) * 1954-03-03 1958-07-01 Svenska Skifferolje Ab Method for in-situ utilization of fuels by combustion
US2862558A (en) * 1955-12-28 1958-12-02 Phillips Petroleum Co Recovering oils from formations
US2890755A (en) * 1953-12-19 1959-06-16 Svenska Skifferolje Ab Apparatus for recovering combustible substances from subterraneous deposits in situ
US2890754A (en) * 1953-10-30 1959-06-16 Svenska Skifferolje Ab Apparatus for recovering combustible substances from subterraneous deposits in situ
US2902270A (en) * 1953-07-17 1959-09-01 Svenska Skifferolje Ab Method of and means in heating of subsurface fuel-containing deposits "in situ"
US2906337A (en) * 1957-08-16 1959-09-29 Pure Oil Co Method of recovering bitumen
US2906340A (en) * 1956-04-05 1959-09-29 Texaco Inc Method of treating a petroleum producing formation
US2914309A (en) * 1953-05-25 1959-11-24 Svenska Skifferolje Ab Oil and gas recovery from tar sands
US2923535A (en) * 1955-02-11 1960-02-02 Svenska Skifferolje Ab Situ recovery from carbonaceous deposits
US2932352A (en) * 1956-10-25 1960-04-12 Union Oil Co Liquid filled well heater
US2939689A (en) * 1947-06-24 1960-06-07 Svenska Skifferolje Ab Electrical heater for treating oilshale and the like
US2950240A (en) * 1958-10-10 1960-08-23 Socony Mobil Oil Co Inc Selective cracking of aliphatic hydrocarbons
US2954826A (en) * 1957-12-02 1960-10-04 William E Sievers Heated well production string
US2958519A (en) * 1958-06-23 1960-11-01 Phillips Petroleum Co In situ combustion process
US2974937A (en) * 1958-11-03 1961-03-14 Jersey Prod Res Co Petroleum recovery from carbonaceous formations
US2994376A (en) * 1957-12-27 1961-08-01 Phillips Petroleum Co In situ combustion process
US2998457A (en) * 1958-11-19 1961-08-29 Ashland Oil Inc Production of phenols
US3004603A (en) * 1958-03-07 1961-10-17 Phillips Petroleum Co Heater
US3007521A (en) * 1957-10-28 1961-11-07 Phillips Petroleum Co Recovery of oil by in situ combustion
US3010513A (en) * 1958-06-12 1961-11-28 Phillips Petroleum Co Initiation of in situ combustion in carbonaceous stratum
US3010516A (en) * 1957-11-18 1961-11-28 Phillips Petroleum Co Burner and process for in situ combustion
US3036632A (en) * 1958-12-24 1962-05-29 Socony Mobil Oil Co Inc Recovery of hydrocarbon materials from earth formations by application of heat
US3044545A (en) * 1958-10-02 1962-07-17 Phillips Petroleum Co In situ combustion process
US3057404A (en) * 1961-09-29 1962-10-09 Socony Mobil Oil Co Inc Method and system for producing oil tenaciously held in porous formations
US3061009A (en) * 1958-01-17 1962-10-30 Svenska Skifferolje Ab Method of recovery from fossil fuel bearing strata
US3062282A (en) * 1958-01-24 1962-11-06 Phillips Petroleum Co Initiation of in situ combustion in a carbonaceous stratum
US3095031A (en) * 1959-12-09 1963-06-25 Eurenius Malte Oscar Burners for use in bore holes in the ground
US3097690A (en) * 1958-12-24 1963-07-16 Gulf Research Development Co Process for heating a subsurface formation
US3105545A (en) * 1960-11-21 1963-10-01 Shell Oil Co Method of heating underground formations
US3106244A (en) * 1960-06-20 1963-10-08 Phillips Petroleum Co Process for producing oil shale in situ by electrocarbonization
US3110345A (en) * 1959-02-26 1963-11-12 Gulf Research Development Co Low temperature reverse combustion process
US3113623A (en) * 1959-07-20 1963-12-10 Union Oil Co Apparatus for underground retorting
US3113619A (en) * 1959-03-30 1963-12-10 Phillips Petroleum Co Line drive counterflow in situ combustion process
US3114417A (en) * 1961-08-14 1963-12-17 Ernest T Saftig Electric oil well heater apparatus
US3116792A (en) * 1959-07-27 1964-01-07 Phillips Petroleum Co In situ combustion process
US3120264A (en) * 1956-07-09 1964-02-04 Texaco Development Corp Recovery of oil by in situ combustion
US3127936A (en) * 1957-07-26 1964-04-07 Svenska Skifferolje Ab Method of in situ heating of subsurface preferably fuel containing deposits
US3127935A (en) * 1960-04-08 1964-04-07 Marathon Oil Co In situ combustion for oil recovery in tar sands, oil shales and conventional petroleum reservoirs
US3131763A (en) * 1959-12-30 1964-05-05 Texaco Inc Electrical borehole heater
US3132692A (en) * 1959-07-27 1964-05-12 Phillips Petroleum Co Use of formation heat from in situ combustion
US3139928A (en) * 1960-05-24 1964-07-07 Shell Oil Co Thermal process for in situ decomposition of oil shale
US3142336A (en) * 1960-07-18 1964-07-28 Shell Oil Co Method and apparatus for injecting steam into subsurface formations
US3149672A (en) * 1962-05-04 1964-09-22 Jersey Prod Res Co Method and apparatus for electrical heating of oil-bearing formations
US3149670A (en) * 1962-03-27 1964-09-22 Smclair Res Inc In-situ heating process
US3150715A (en) * 1959-09-30 1964-09-29 Shell Oil Co Oil recovery by in situ combustion with water injection
US3163745A (en) * 1960-02-29 1964-12-29 Socony Mobil Oil Co Inc Heating of an earth formation penetrated by a well borehole
US3164207A (en) * 1961-01-17 1965-01-05 Wayne H Thessen Method for recovering oil
US3181613A (en) * 1959-07-20 1965-05-04 Union Oil Co Method and apparatus for subterranean heating
US3182721A (en) * 1962-11-02 1965-05-11 Sun Oil Co Method of petroleum production by forward in situ combustion
US3183675A (en) * 1961-11-02 1965-05-18 Conch Int Methane Ltd Method of freezing an earth formation
US3191679A (en) * 1961-04-13 1965-06-29 Wendell S Miller Melting process for recovering bitumens from the earth
US3205946A (en) * 1962-03-12 1965-09-14 Shell Oil Co Consolidation by silica coalescence
US3205944A (en) * 1963-06-14 1965-09-14 Socony Mobil Oil Co Inc Recovery of hydrocarbons from a subterranean reservoir by heating
US3207220A (en) * 1961-06-26 1965-09-21 Chester I Williams Electric well heater
US3208531A (en) * 1962-08-21 1965-09-28 Otis Eng Co Inserting tool for locating and anchoring a device in tubing
US3209825A (en) * 1962-02-14 1965-10-05 Continental Oil Co Low temperature in-situ combustion
US20040062340A1 (en) * 2002-09-16 2004-04-01 Peterson Otis G. Self-regulating nuclear power module
US6782947B2 (en) * 2001-04-24 2004-08-31 Shell Oil Company In situ thermal processing of a relatively impermeable formation to increase permeability of the formation
US6991036B2 (en) * 2001-04-24 2006-01-31 Shell Oil Company Thermal processing of a relatively permeable formation

Family Cites Families (951)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US345586A (en) 1886-07-13 Oil from wells
SE126674C1 (ru) 1949-01-01
US1457690A (en) * 1923-06-05 Percival iv brine
CA899987A (en) 1972-05-09 Chisso Corporation Method for controlling heat generation locally in a heat-generating pipe utilizing skin effect current
SE123138C1 (ru) 1948-01-01
SE123136C1 (ru) 1948-01-01
US1269747A (en) 1918-04-06 1918-06-18 Lebbeus H Rogers Method of and apparatus for treating oil-shale.
GB156396A (en) 1919-12-10 1921-01-13 Wilson Woods Hoover An improved method of treating shale and recovering oil therefrom
US1457479A (en) * 1920-01-12 1923-06-05 Edson R Wolcott Method of increasing the yield of oil wells
US1477802A (en) 1921-02-28 1923-12-18 Cutler Hammer Mfg Co Oil-well heater
US1646599A (en) 1925-04-30 1927-10-25 George A Schaefer Apparatus for removing fluid from wells
US1811560A (en) 1926-04-08 1931-06-23 Standard Oil Dev Co Method of and apparatus for recovering oil
US2011710A (en) 1928-08-18 1935-08-20 Nat Aniline & Chem Co Inc Apparatus for measuring temperature
US2013838A (en) 1932-12-27 1935-09-10 Rowland O Pickin Roller core drilling bit
US2288857A (en) * 1937-10-18 1942-07-07 Union Oil Co Process for the removal of bitumen from bituminous deposits
US2244255A (en) * 1939-01-18 1941-06-03 Electrical Treating Company Well clearing system
US2208087A (en) * 1939-11-06 1940-07-16 Carlton J Somers Electric heater
US2249926A (en) 1940-05-13 1941-07-22 John A Zublin Nontracking roller bit
US2319702A (en) 1941-04-04 1943-05-18 Socony Vacuum Oil Co Inc Method and apparatus for producing oil wells
US2381256A (en) 1942-10-06 1945-08-07 Texas Co Process for treating hydrocarbon fractions
US2390770A (en) 1942-10-10 1945-12-11 Sun Oil Co Method of producing petroleum
US2595728A (en) * 1945-03-09 1952-05-06 Westinghouse Electric Corp Polysiloxanes containing allyl radicals
US2481051A (en) 1945-12-15 1949-09-06 Texaco Development Corp Process and apparatus for the recovery of volatilizable constituents from underground carbonaceous formations
US2500305A (en) * 1946-05-28 1950-03-14 Thermactor Corp Electric oil well heater
GB674082A (en) 1949-06-15 1952-06-18 Nat Res Dev Improvements in or relating to the underground gasification of coal
GB676543A (en) 1949-11-14 1952-07-30 Telegraph Constr & Maintenance Improvements in the moulding and jointing of thermoplastic materials for example in the jointing of electric cables
US2623596A (en) 1950-05-16 1952-12-30 Atlantic Refining Co Method for producing oil by means of carbon dioxide
US2647196A (en) * 1950-11-06 1953-07-28 Union Oil Co Apparatus for heating oil wells
US2647306A (en) 1951-04-14 1953-08-04 John C Hockery Can opener
US2757739A (en) 1952-01-07 1956-08-07 Parelex Corp Heating apparatus
US2759877A (en) 1952-03-18 1956-08-21 Sinclair Refining Co Process and separation apparatus for use in the conversions of hydrocarbons
US2761663A (en) 1952-09-05 1956-09-04 Louis F Gerdetz Process of underground gasification of coal
US2825408A (en) 1953-03-09 1958-03-04 Sinclair Oil & Gas Company Oil recovery by subsurface thermal processing
US2743906A (en) 1953-05-08 1956-05-01 William E Coyle Hydraulic underreamer
US2803305A (en) 1953-05-14 1957-08-20 Pan American Petroleum Corp Oil recovery by underground combustion
US2794504A (en) 1954-05-10 1957-06-04 Union Oil Co Well heater
US2781851A (en) * 1954-10-11 1957-02-19 Shell Dev Well tubing heater system
US2801699A (en) 1954-12-24 1957-08-06 Pure Oil Co Process for temporarily and selectively sealing a well
US2787325A (en) 1954-12-24 1957-04-02 Pure Oil Co Selective treatment of geological formations
US2799341A (en) 1955-03-04 1957-07-16 Union Oil Co Selective plugging in oil wells
US2801089A (en) 1955-03-14 1957-07-30 California Research Corp Underground shale retorting process
US2818118A (en) 1955-12-19 1957-12-31 Phillips Petroleum Co Production of oil by in situ combustion
US2819761A (en) 1956-01-19 1958-01-14 Continental Oil Co Process of removing viscous oil from a well bore
US2857002A (en) 1956-03-19 1958-10-21 Texas Co Recovery of viscous crude oil
US2991046A (en) 1956-04-16 1961-07-04 Parsons Lional Ashley Combined winch and bollard device
US2889882A (en) * 1956-06-06 1959-06-09 Phillips Petroleum Co Oil recovery by in situ combustion
US3016053A (en) 1956-08-02 1962-01-09 George J Medovick Underwater breathing apparatus
US2997105A (en) * 1956-10-08 1961-08-22 Pan American Petroleum Corp Burner apparatus
US2942223A (en) 1957-08-09 1960-06-21 Gen Electric Electrical resistance heater
US3080918A (en) * 1957-08-29 1963-03-12 Richfield Oil Corp Petroleum recovery from subsurface oil bearing formation
GB876401A (en) * 1957-12-23 1961-08-30 Exxon Research Engineering Co Moving bed nuclear reactor for process irradiation
US3085957A (en) * 1957-12-26 1963-04-16 Richfield Oil Corp Nuclear reactor for heating a subsurface stratum
US3051235A (en) 1958-02-24 1962-08-28 Jersey Prod Res Co Recovery of petroleum crude oil, by in situ combustion and in situ hydrogenation
US3032102A (en) 1958-03-17 1962-05-01 Phillips Petroleum Co In situ combustion method
US3079995A (en) * 1958-04-16 1963-03-05 Richfield Oil Corp Petroleum recovery from subsurface oil-bearing formation
US3004601A (en) 1958-05-09 1961-10-17 Albert G Bodine Method and apparatus for augmenting oil recovery from wells by refrigeration
US3048221A (en) 1958-05-12 1962-08-07 Phillips Petroleum Co Hydrocarbon recovery by thermal drive
US3026940A (en) 1958-05-19 1962-03-27 Electronic Oil Well Heater Inc Oil well temperature indicator and control
US3050123A (en) 1958-10-07 1962-08-21 Cities Service Res & Dev Co Gas fired oil-well burner
US2970826A (en) 1958-11-21 1961-02-07 Texaco Inc Recovery of oil from oil shale
US2937228A (en) * 1958-12-29 1960-05-17 Robinson Machine Works Inc Coaxial cable splice
US2969226A (en) 1959-01-19 1961-01-24 Pyrochem Corp Pendant parting petro pyrolysis process
US3017168A (en) 1959-01-26 1962-01-16 Phillips Petroleum Co In situ retorting of oil shale
US3113620A (en) 1959-07-06 1963-12-10 Exxon Research Engineering Co Process for producing viscous oil
US3220479A (en) 1960-02-08 1965-11-30 Exxon Production Research Co Formation stabilization system
US3137347A (en) 1960-05-09 1964-06-16 Phillips Petroleum Co In situ electrolinking of oil shale
US3138203A (en) 1961-03-06 1964-06-23 Jersey Prod Res Co Method of underground burning
US3246695A (en) 1961-08-21 1966-04-19 Charles L Robinson Method for heating minerals in situ with radioactive materials
US3170842A (en) 1961-11-06 1965-02-23 Phillips Petroleum Co Subcritical borehole nuclear reactor and process
US3141924A (en) 1962-03-16 1964-07-21 Amp Inc Coaxial cable shield braid terminators
US3165154A (en) 1962-03-23 1965-01-12 Phillips Petroleum Co Oil recovery by in situ combustion
US3288648A (en) 1963-02-04 1966-11-29 Pan American Petroleum Corp Process for producing electrical energy from geological liquid hydrocarbon formation
US3205942A (en) 1963-02-07 1965-09-14 Socony Mobil Oil Co Inc Method for recovery of hydrocarbons by in situ heating of oil shale
US3221505A (en) 1963-02-20 1965-12-07 Gulf Research Development Co Grouting method
US3221811A (en) 1963-03-11 1965-12-07 Shell Oil Co Mobile in-situ heating of formations
US3250327A (en) 1963-04-02 1966-05-10 Socony Mobil Oil Co Inc Recovering nonflowing hydrocarbons
US3241611A (en) 1963-04-10 1966-03-22 Equity Oil Company Recovery of petroleum products from oil shale
GB959945A (en) 1963-04-18 1964-06-03 Conch Int Methane Ltd Constructing a frozen wall within the ground
US3237689A (en) * 1963-04-29 1966-03-01 Clarence I Justheim Distillation of underground deposits of solid carbonaceous materials in situ
US3233668A (en) * 1963-11-15 1966-02-08 Exxon Production Research Co Recovery of shale oil
US3285335A (en) 1963-12-11 1966-11-15 Exxon Research Engineering Co In situ pyrolysis of oil shale formations
US3273640A (en) 1963-12-13 1966-09-20 Pyrochem Corp Pressure pulsing perpendicular permeability process for winning stabilized primary volatiles from oil shale in situ
US3272261A (en) 1963-12-13 1966-09-13 Gulf Research Development Co Process for recovery of oil
US3303883A (en) 1964-01-06 1967-02-14 Mobil Oil Corp Thermal notching technique
US3275076A (en) 1964-01-13 1966-09-27 Mobil Oil Corp Recovery of asphaltic-type petroleum from a subterranean reservoir
US3342258A (en) 1964-03-06 1967-09-19 Shell Oil Co Underground oil recovery from solid oil-bearing deposits
US3294167A (en) 1964-04-13 1966-12-27 Shell Oil Co Thermal oil recovery
US3284281A (en) 1964-08-31 1966-11-08 Phillips Petroleum Co Production of oil from oil shale through fractures
US3302707A (en) 1964-09-30 1967-02-07 Mobil Oil Corp Method for improving fluid recoveries from earthen formations
US3310109A (en) 1964-11-06 1967-03-21 Phillips Petroleum Co Process and apparatus for combination upgrading of oil in situ and refining thereof
US3380913A (en) 1964-12-28 1968-04-30 Phillips Petroleum Co Refining of effluent from in situ combustion operation
US3262500A (en) * 1965-03-01 1966-07-26 Beehler Vernon D Hot water flood system for oil wells
US3332480A (en) 1965-03-04 1967-07-25 Pan American Petroleum Corp Recovery of hydrocarbons by thermal methods
US3338306A (en) 1965-03-09 1967-08-29 Mobil Oil Corp Recovery of heavy oil from oil sands
US3358756A (en) * 1965-03-12 1967-12-19 Shell Oil Co Method for in situ recovery of solid or semi-solid petroleum deposits
US3299202A (en) 1965-04-02 1967-01-17 Okonite Co Oil well cable
DE1242535B (de) 1965-04-13 1967-06-22 Deutsche Erdoel Ag Verfahren zur Restausfoerderung von Erdoellagerstaetten
US3316344A (en) 1965-04-26 1967-04-25 Central Electr Generat Board Prevention of icing of electrical conductors
US3342267A (en) 1965-04-29 1967-09-19 Gerald S Cotter Turbo-generator heater for oil and gas wells and pipe lines
US3352355A (en) 1965-06-23 1967-11-14 Dow Chemical Co Method of recovery of hydrocarbons from solid hydrocarbonaceous formations
US3346044A (en) 1965-09-08 1967-10-10 Mobil Oil Corp Method and structure for retorting oil shale in situ by cycling fluid flows
US3349845A (en) 1965-10-22 1967-10-31 Sinclair Oil & Gas Company Method of establishing communication between wells
US3386515A (en) * 1965-12-03 1968-06-04 Dresser Ind Well completion apparatus
US3379248A (en) 1965-12-10 1968-04-23 Mobil Oil Corp In situ combustion process utilizing waste heat
US3386508A (en) 1966-02-21 1968-06-04 Exxon Production Research Co Process and system for the recovery of viscous oil
US3362751A (en) 1966-02-28 1968-01-09 Tinlin William Method and system for recovering shale oil and gas
US3595082A (en) 1966-03-04 1971-07-27 Gulf Oil Corp Temperature measuring apparatus
US3410977A (en) 1966-03-28 1968-11-12 Ando Masao Method of and apparatus for heating the surface part of various construction materials
DE1615192B1 (de) 1966-04-01 1970-08-20 Chisso Corp Induktiv beheiztes Heizrohr
US3410796A (en) 1966-04-04 1968-11-12 Gas Processors Inc Process for treatment of saline waters
US3513913A (en) 1966-04-19 1970-05-26 Shell Oil Co Oil recovery from oil shales by transverse combustion
US3372754A (en) 1966-05-31 1968-03-12 Mobil Oil Corp Well assembly for heating a subterranean formation
US3399623A (en) 1966-07-14 1968-09-03 James R. Creed Apparatus for and method of producing viscid oil
US3428125A (en) * 1966-07-25 1969-02-18 Phillips Petroleum Co Hydro-electropyrolysis of oil shale in situ
US3412011A (en) 1966-09-02 1968-11-19 Phillips Petroleum Co Catalytic cracking and in situ combustion process for producing hydrocarbons
NL153755C (nl) 1966-10-20 1977-11-15 Stichting Reactor Centrum Werkwijze voor het vervaardigen van een elektrisch verwarmingselement, alsmede verwarmingselement vervaardigd met toepassing van deze werkwijze.
US3465819A (en) 1967-02-13 1969-09-09 American Oil Shale Corp Use of nuclear detonations in producing hydrocarbons from an underground formation
US3389975A (en) 1967-03-10 1968-06-25 Sinclair Research Inc Process for the recovery of aluminum values from retorted shale and conversion of sodium aluminate to sodium aluminum carbonate hydroxide
NL6803827A (ru) 1967-03-22 1968-09-23
US3515213A (en) 1967-04-19 1970-06-02 Shell Oil Co Shale oil recovery process using heated oil-miscible fluids
US3598182A (en) * 1967-04-25 1971-08-10 Justheim Petroleum Co Method and apparatus for in situ distillation and hydrogenation of carbonaceous materials
US3474863A (en) 1967-07-28 1969-10-28 Shell Oil Co Shale oil extraction process
US3528501A (en) 1967-08-04 1970-09-15 Phillips Petroleum Co Recovery of oil from oil shale
US3480082A (en) 1967-09-25 1969-11-25 Continental Oil Co In situ retorting of oil shale using co2 as heat carrier
US3434541A (en) 1967-10-11 1969-03-25 Mobil Oil Corp In situ combustion process
NL154577B (nl) * 1967-11-15 1977-09-15 Shell Int Research Werkwijze voor het winnen van koolwaterstoffen vanuit een permeabele ondergrondse formatie.
US3485300A (en) 1967-12-20 1969-12-23 Phillips Petroleum Co Method and apparatus for defoaming crude oil down hole
US3477058A (en) 1968-02-01 1969-11-04 Gen Electric Magnesia insulated heating elements and methods of production
US3580987A (en) 1968-03-26 1971-05-25 Pirelli Electric cable
US3487753A (en) 1968-04-10 1970-01-06 Dresser Ind Well swab cup
US3455383A (en) 1968-04-24 1969-07-15 Shell Oil Co Method of producing fluidized material from a subterranean formation
US3578080A (en) 1968-06-10 1971-05-11 Shell Oil Co Method of producing shale oil from an oil shale formation
US3529682A (en) 1968-10-03 1970-09-22 Bell Telephone Labor Inc Location detection and guidance systems for burrowing device
US3537528A (en) 1968-10-14 1970-11-03 Shell Oil Co Method for producing shale oil from an exfoliated oil shale formation
US3593789A (en) 1968-10-18 1971-07-20 Shell Oil Co Method for producing shale oil from an oil shale formation
US3502372A (en) 1968-10-23 1970-03-24 Shell Oil Co Process of recovering oil and dawsonite from oil shale
US3565171A (en) 1968-10-23 1971-02-23 Shell Oil Co Method for producing shale oil from a subterranean oil shale formation
US3554285A (en) 1968-10-24 1971-01-12 Phillips Petroleum Co Production and upgrading of heavy viscous oils
US3629551A (en) 1968-10-29 1971-12-21 Chisso Corp Controlling heat generation locally in a heat-generating pipe utilizing skin-effect current
US3501201A (en) 1968-10-30 1970-03-17 Shell Oil Co Method of producing shale oil from a subterranean oil shale formation
US3617471A (en) 1968-12-26 1971-11-02 Texaco Inc Hydrotorting of shale to produce shale oil
US3562401A (en) 1969-03-03 1971-02-09 Union Carbide Corp Low temperature electric transmission systems
US3614986A (en) 1969-03-03 1971-10-26 Electrothermic Co Method for injecting heated fluids into mineral bearing formations
US3542131A (en) 1969-04-01 1970-11-24 Mobil Oil Corp Method of recovering hydrocarbons from oil shale
US3547192A (en) 1969-04-04 1970-12-15 Shell Oil Co Method of metal coating and electrically heating a subterranean earth formation
US3618663A (en) 1969-05-01 1971-11-09 Phillips Petroleum Co Shale oil production
US3605890A (en) 1969-06-04 1971-09-20 Chevron Res Hydrogen production from a kerogen-depleted shale formation
US3526095A (en) 1969-07-24 1970-09-01 Ralph E Peck Liquid gas storage system
DE1939402B2 (de) 1969-08-02 1970-12-03 Felten & Guilleaume Kabelwerk Verfahren und Vorrichtung zum Wellen von Rohrwandungen
US3599714A (en) 1969-09-08 1971-08-17 Roger L Messman Method of recovering hydrocarbons by in situ combustion
US3547193A (en) 1969-10-08 1970-12-15 Electrothermic Co Method and apparatus for recovery of minerals from sub-surface formations using electricity
US3661423A (en) 1970-02-12 1972-05-09 Occidental Petroleum Corp In situ process for recovery of carbonaceous materials from subterranean deposits
US3943160A (en) 1970-03-09 1976-03-09 Shell Oil Company Heat-stable calcium-compatible waterflood surfactant
US3647358A (en) 1970-07-23 1972-03-07 Anti Pollution Systems Method of catalytically inducing oxidation of carbonaceous materials by the use of molten salts
US3657520A (en) * 1970-08-20 1972-04-18 Michel A Ragault Heating cable with cold outlets
US3759574A (en) 1970-09-24 1973-09-18 Shell Oil Co Method of producing hydrocarbons from an oil shale formation
US4305463A (en) 1979-10-31 1981-12-15 Oil Trieval Corporation Oil recovery method and apparatus
US3703929A (en) * 1970-11-06 1972-11-28 Union Oil Co Well for transporting hot fluids through a permafrost zone
US3679812A (en) 1970-11-13 1972-07-25 Schlumberger Technology Corp Electrical suspension cable for well tools
US3680633A (en) 1970-12-28 1972-08-01 Sun Oil Co Delaware Situ combustion initiation process
US3675715A (en) 1970-12-30 1972-07-11 Forrester A Clark Processes for secondarily recovering oil
US3700280A (en) 1971-04-28 1972-10-24 Shell Oil Co Method of producing oil from an oil shale formation containing nahcolite and dawsonite
US3770398A (en) 1971-09-17 1973-11-06 Cities Service Oil Co In situ coal gasification process
US3743854A (en) 1971-09-29 1973-07-03 Gen Electric System and apparatus for dual transmission of petrochemical fluids and unidirectional electric current
US3812913A (en) 1971-10-18 1974-05-28 Sun Oil Co Method of formation consolidation
US3782465A (en) * 1971-11-09 1974-01-01 Electro Petroleum Electro-thermal process for promoting oil recovery
US3893918A (en) 1971-11-22 1975-07-08 Engineering Specialties Inc Method for separating material leaving a well
US3844352A (en) 1971-12-17 1974-10-29 Brown Oil Tools Method for modifying a well to provide gas lift production
US3766982A (en) 1971-12-27 1973-10-23 Justheim Petrol Co Method for the in-situ treatment of hydrocarbonaceous materials
US3759328A (en) 1972-05-11 1973-09-18 Shell Oil Co Laterally expanding oil shale permeabilization
US3794116A (en) 1972-05-30 1974-02-26 Atomic Energy Commission Situ coal bed gasification
US3779602A (en) 1972-08-07 1973-12-18 Shell Oil Co Process for solution mining nahcolite
US3757860A (en) 1972-08-07 1973-09-11 Atlantic Richfield Co Well heating
US3761599A (en) 1972-09-05 1973-09-25 Gen Electric Means for reducing eddy current heating of a tank in electric apparatus
US3809159A (en) 1972-10-02 1974-05-07 Continental Oil Co Process for simultaneously increasing recovery and upgrading oil in a reservoir
US3804172A (en) 1972-10-11 1974-04-16 Shell Oil Co Method for the recovery of oil from oil shale
US3794113A (en) 1972-11-13 1974-02-26 Mobil Oil Corp Combination in situ combustion displacement and steam stimulation of producing wells
US3804169A (en) 1973-02-07 1974-04-16 Shell Oil Co Spreading-fluid recovery of subterranean oil
US3896260A (en) 1973-04-03 1975-07-22 Walter A Plummer Powder filled cable splice assembly
US3947683A (en) 1973-06-05 1976-03-30 Texaco Inc. Combination of epithermal and inelastic neutron scattering methods to locate coal and oil shale zones
US3859503A (en) * 1973-06-12 1975-01-07 Richard D Palone Electric heated sucker rod
US4076761A (en) 1973-08-09 1978-02-28 Mobil Oil Corporation Process for the manufacture of gasoline
US3881551A (en) 1973-10-12 1975-05-06 Ruel C Terry Method of extracting immobile hydrocarbons
US3907045A (en) 1973-11-30 1975-09-23 Continental Oil Co Guidance system for a horizontal drilling apparatus
US3853185A (en) 1973-11-30 1974-12-10 Continental Oil Co Guidance system for a horizontal drilling apparatus
US3882941A (en) 1973-12-17 1975-05-13 Cities Service Res & Dev Co In situ production of bitumen from oil shale
US3946812A (en) 1974-01-02 1976-03-30 Exxon Production Research Company Use of materials as waterflood additives
US4037655A (en) 1974-04-19 1977-07-26 Electroflood Company Method for secondary recovery of oil
US4199025A (en) 1974-04-19 1980-04-22 Electroflood Company Method and apparatus for tertiary recovery of oil
US3922148A (en) 1974-05-16 1975-11-25 Texaco Development Corp Production of methane-rich gas
US3948755A (en) 1974-05-31 1976-04-06 Standard Oil Company Process for recovering and upgrading hydrocarbons from oil shale and tar sands
ZA753184B (en) 1974-05-31 1976-04-28 Standard Oil Co Process for recovering upgraded hydrocarbon products
US3892270A (en) 1974-06-06 1975-07-01 Chevron Res Production of hydrocarbons from underground formations
US3894769A (en) 1974-06-06 1975-07-15 Shell Oil Co Recovering oil from a subterranean carbonaceous formation
GB1507675A (en) 1974-06-21 1978-04-19 Pyrotenax Of Ca Ltd Heating cables and manufacture thereof
US4006778A (en) 1974-06-21 1977-02-08 Texaco Exploration Canada Ltd. Thermal recovery of hydrocarbon from tar sands
US4026357A (en) 1974-06-26 1977-05-31 Texaco Exploration Canada Ltd. In situ gasification of solid hydrocarbon materials in a subterranean formation
US3935911A (en) 1974-06-28 1976-02-03 Dresser Industries, Inc. Earth boring bit with means for conducting heat from the bit's bearings
US4014575A (en) 1974-07-26 1977-03-29 Occidental Petroleum Corporation System for fuel and products of oil shale retort
US4029360A (en) 1974-07-26 1977-06-14 Occidental Oil Shale, Inc. Method of recovering oil and water from in situ oil shale retort flue gas
US4005752A (en) 1974-07-26 1977-02-01 Occidental Petroleum Corporation Method of igniting in situ oil shale retort with fuel rich flue gas
US3941421A (en) 1974-08-13 1976-03-02 Occidental Petroleum Corporation Apparatus for obtaining uniform gas flow through an in situ oil shale retort
GB1454324A (en) 1974-08-14 1976-11-03 Iniex Recovering combustible gases from underground deposits of coal or bituminous shale
US3948319A (en) 1974-10-16 1976-04-06 Atlantic Richfield Company Method and apparatus for producing fluid by varying current flow through subterranean source formation
AR205595A1 (es) 1974-11-06 1976-05-14 Haldor Topsoe As Procedimiento para preparar gases rico en metano
US3933447A (en) 1974-11-08 1976-01-20 The United States Of America As Represented By The United States Energy Research And Development Administration Underground gasification of coal
US4138442A (en) 1974-12-05 1979-02-06 Mobil Oil Corporation Process for the manufacture of gasoline
US3952802A (en) 1974-12-11 1976-04-27 In Situ Technology, Inc. Method and apparatus for in situ gasification of coal and the commercial products derived therefrom
US3986556A (en) 1975-01-06 1976-10-19 Haynes Charles A Hydrocarbon recovery from earth strata
US3958636A (en) 1975-01-23 1976-05-25 Atlantic Richfield Company Production of bitumen from a tar sand formation
US4042026A (en) 1975-02-08 1977-08-16 Deutsche Texaco Aktiengesellschaft Method for initiating an in-situ recovery process by the introduction of oxygen
US3972372A (en) 1975-03-10 1976-08-03 Fisher Sidney T Exraction of hydrocarbons in situ from underground hydrocarbon deposits
US4096163A (en) 1975-04-08 1978-06-20 Mobil Oil Corporation Conversion of synthesis gas to hydrocarbon mixtures
US3924680A (en) 1975-04-23 1975-12-09 In Situ Technology Inc Method of pyrolysis of coal in situ
US3973628A (en) 1975-04-30 1976-08-10 New Mexico Tech Research Foundation In situ solution mining of coal
US4016239A (en) 1975-05-22 1977-04-05 Union Oil Company Of California Recarbonation of spent oil shale
US3987851A (en) 1975-06-02 1976-10-26 Shell Oil Company Serially burning and pyrolyzing to produce shale oil from a subterranean oil shale
US3986557A (en) 1975-06-06 1976-10-19 Atlantic Richfield Company Production of bitumen from tar sands
US3950029A (en) 1975-06-12 1976-04-13 Mobil Oil Corporation In situ retorting of oil shale
US3993132A (en) 1975-06-18 1976-11-23 Texaco Exploration Canada Ltd. Thermal recovery of hydrocarbons from tar sands
US4069868A (en) 1975-07-14 1978-01-24 In Situ Technology, Inc. Methods of fluidized production of coal in situ
US4199024A (en) 1975-08-07 1980-04-22 World Energy Systems Multistage gas generator
US3954140A (en) 1975-08-13 1976-05-04 Hendrick Robert P Recovery of hydrocarbons by in situ thermal extraction
US3986349A (en) 1975-09-15 1976-10-19 Chevron Research Company Method of power generation via coal gasification and liquid hydrocarbon synthesis
US3994340A (en) 1975-10-30 1976-11-30 Chevron Research Company Method of recovering viscous petroleum from tar sand
US4037658A (en) 1975-10-30 1977-07-26 Chevron Research Company Method of recovering viscous petroleum from an underground formation
US3994341A (en) 1975-10-30 1976-11-30 Chevron Research Company Recovering viscous petroleum from thick tar sand
US4087130A (en) 1975-11-03 1978-05-02 Occidental Petroleum Corporation Process for the gasification of coal in situ
US4018279A (en) 1975-11-12 1977-04-19 Reynolds Merrill J In situ coal combustion heat recovery method
US4018280A (en) 1975-12-10 1977-04-19 Mobil Oil Corporation Process for in situ retorting of oil shale
US3992474A (en) 1975-12-15 1976-11-16 Uop Inc. Motor fuel production with fluid catalytic cracking of high-boiling alkylate
US4019575A (en) 1975-12-22 1977-04-26 Chevron Research Company System for recovering viscous petroleum from thick tar sand
US3999607A (en) 1976-01-22 1976-12-28 Exxon Research And Engineering Company Recovery of hydrocarbons from coal
US4031956A (en) 1976-02-12 1977-06-28 In Situ Technology, Inc. Method of recovering energy from subsurface petroleum reservoirs
US4008762A (en) 1976-02-26 1977-02-22 Fisher Sidney T Extraction of hydrocarbons in situ from underground hydrocarbon deposits
US4010800A (en) 1976-03-08 1977-03-08 In Situ Technology, Inc. Producing thin seams of coal in situ
US4048637A (en) 1976-03-23 1977-09-13 Westinghouse Electric Corporation Radar system for detecting slowly moving targets
DE2615874B2 (de) 1976-04-10 1978-10-19 Deutsche Texaco Ag, 2000 Hamburg Anwendung eines Verfahrens zum Gewinnen von Erdöl und Bitumen aus unterirdischen Lagerstätten mittels einer Verbrennungfront bei Lagerstätten beliebigen Gehalts an intermediären Kohlenwasserstoffen im Rohöl bzw. Bitumen
US4022280A (en) * 1976-05-17 1977-05-10 Stoddard Xerxes T Thermal recovery of hydrocarbons by washing an underground sand
GB1544245A (en) 1976-05-21 1979-04-19 British Gas Corp Production of substitute natural gas
US4049053A (en) 1976-06-10 1977-09-20 Fisher Sidney T Recovery of hydrocarbons from partially exhausted oil wells by mechanical wave heating
US4487257A (en) 1976-06-17 1984-12-11 Raytheon Company Apparatus and method for production of organic products from kerogen
US4193451A (en) 1976-06-17 1980-03-18 The Badger Company, Inc. Method for production of organic products from kerogen
US4067390A (en) 1976-07-06 1978-01-10 Technology Application Services Corporation Apparatus and method for the recovery of fuel products from subterranean deposits of carbonaceous matter using a plasma arc
US4057293A (en) 1976-07-12 1977-11-08 Garrett Donald E Process for in situ conversion of coal or the like into oil and gas
US4043393A (en) 1976-07-29 1977-08-23 Fisher Sidney T Extraction from underground coal deposits
US4091869A (en) 1976-09-07 1978-05-30 Exxon Production Research Company In situ process for recovery of carbonaceous materials from subterranean deposits
US4083604A (en) 1976-11-15 1978-04-11 Trw Inc. Thermomechanical fracture for recovery system in oil shale deposits
US4065183A (en) 1976-11-15 1977-12-27 Trw Inc. Recovery system for oil shale deposits
US4059308A (en) 1976-11-15 1977-11-22 Trw Inc. Pressure swing recovery system for oil shale deposits
US4077471A (en) 1976-12-01 1978-03-07 Texaco Inc. Surfactant oil recovery process usable in high temperature, high salinity formations
US4064943A (en) 1976-12-06 1977-12-27 Shell Oil Co Plugging permeable earth formation with wax
US4084637A (en) 1976-12-16 1978-04-18 Petro Canada Exploration Inc. Method of producing viscous materials from subterranean formations
US4089374A (en) 1976-12-16 1978-05-16 In Situ Technology, Inc. Producing methane from coal in situ
US4093026A (en) 1977-01-17 1978-06-06 Occidental Oil Shale, Inc. Removal of sulfur dioxide from process gas using treated oil shale and water
US4102418A (en) 1977-01-24 1978-07-25 Bakerdrill Inc. Borehole drilling apparatus
US4277416A (en) 1977-02-17 1981-07-07 Aminoil, Usa, Inc. Process for producing methanol
US4085803A (en) 1977-03-14 1978-04-25 Exxon Production Research Company Method for oil recovery using a horizontal well with indirect heating
US4151877A (en) 1977-05-13 1979-05-01 Occidental Oil Shale, Inc. Determining the locus of a processing zone in a retort through channels
US4099567A (en) 1977-05-27 1978-07-11 In Situ Technology, Inc. Generating medium BTU gas from coal in situ
US4169506A (en) 1977-07-15 1979-10-02 Standard Oil Company (Indiana) In situ retorting of oil shale and energy recovery
US4144935A (en) 1977-08-29 1979-03-20 Iit Research Institute Apparatus and method for in situ heat processing of hydrocarbonaceous formations
US4140180A (en) 1977-08-29 1979-02-20 Iit Research Institute Method for in situ heat processing of hydrocarbonaceous formations
NL181941C (nl) 1977-09-16 1987-12-01 Ir Arnold Willem Josephus Grup Werkwijze voor het ondergronds vergassen van steenkool of bruinkool.
US4125159A (en) 1977-10-17 1978-11-14 Vann Roy Randell Method and apparatus for isolating and treating subsurface stratas
SU915451A1 (ru) 1977-10-21 1988-08-23 Vnii Ispolzovania Способ подземной газификации топлива
US4119349A (en) 1977-10-25 1978-10-10 Gulf Oil Corporation Method and apparatus for recovery of fluids produced in in-situ retorting of oil shale
US4114688A (en) 1977-12-05 1978-09-19 In Situ Technology Inc. Minimizing environmental effects in production and use of coal
US4158467A (en) 1977-12-30 1979-06-19 Gulf Oil Corporation Process for recovering shale oil
US4196914A (en) * 1978-01-13 1980-04-08 Dresser Industries, Inc. Chuck for an earth boring machine
US4148359A (en) 1978-01-30 1979-04-10 Shell Oil Company Pressure-balanced oil recovery process for water productive oil shale
DE2812490A1 (de) 1978-03-22 1979-09-27 Texaco Ag Verfahren zur ermittlung der raeumlichen ausdehnung von untertaegigen reaktionen
US4162707A (en) 1978-04-20 1979-07-31 Mobil Oil Corporation Method of treating formation to remove ammonium ions
US4197911A (en) 1978-05-09 1980-04-15 Ramcor, Inc. Process for in situ coal gasification
US4228853A (en) 1978-06-21 1980-10-21 Harvey A Herbert Petroleum production method
US4186801A (en) 1978-12-18 1980-02-05 Gulf Research And Development Company In situ combustion process for the recovery of liquid carbonaceous fuels from subterranean formations
US4185692A (en) 1978-07-14 1980-01-29 In Situ Technology, Inc. Underground linkage of wells for production of coal in situ
US4184548A (en) 1978-07-17 1980-01-22 Standard Oil Company (Indiana) Method for determining the position and inclination of a flame front during in situ combustion of an oil shale retort
US4257650A (en) * 1978-09-07 1981-03-24 Barber Heavy Oil Process, Inc. Method for recovering subsurface earth substances
US4183405A (en) 1978-10-02 1980-01-15 Magnie Robert L Enhanced recoveries of petroleum and hydrogen from underground reservoirs
US4446917A (en) 1978-10-04 1984-05-08 Todd John C Method and apparatus for producing viscous or waxy crude oils
US4457365A (en) 1978-12-07 1984-07-03 Raytheon Company In situ radio frequency selective heating system
US4299086A (en) 1978-12-07 1981-11-10 Gulf Research & Development Company Utilization of energy obtained by substoichiometric combustion of low heating value gases
US4265307A (en) 1978-12-20 1981-05-05 Standard Oil Company Shale oil recovery
US4194562A (en) 1978-12-21 1980-03-25 Texaco Inc. Method for preconditioning a subterranean oil-bearing formation prior to in-situ combustion
US4258955A (en) 1978-12-26 1981-03-31 Mobil Oil Corporation Process for in-situ leaching of uranium
US4274487A (en) 1979-01-11 1981-06-23 Standard Oil Company (Indiana) Indirect thermal stimulation of production wells
US4260192A (en) 1979-02-21 1981-04-07 Occidental Research Corporation Recovery of magnesia from oil shale
US4324292A (en) 1979-02-21 1982-04-13 University Of Utah Process for recovering products from oil shale
US4243511A (en) 1979-03-26 1981-01-06 Marathon Oil Company Process for suppressing carbonate decomposition in vapor phase water retorting
US4248306A (en) 1979-04-02 1981-02-03 Huisen Allan T Van Geothermal petroleum refining
US4282587A (en) 1979-05-21 1981-08-04 Daniel Silverman Method for monitoring the recovery of minerals from shallow geological formations
US4216079A (en) 1979-07-09 1980-08-05 Cities Service Company Emulsion breaking with surfactant recovery
US4234230A (en) 1979-07-11 1980-11-18 The Superior Oil Company In situ processing of mined oil shale
US4228854A (en) 1979-08-13 1980-10-21 Alberta Research Council Enhanced oil recovery using electrical means
US4701587A (en) 1979-08-31 1987-10-20 Metcal, Inc. Shielded heating element having intrinsic temperature control
US4256945A (en) 1979-08-31 1981-03-17 Iris Associates Alternating current electrically resistive heating element having intrinsic temperature control
US4327805A (en) 1979-09-18 1982-05-04 Carmel Energy, Inc. Method for producing viscous hydrocarbons
US4549396A (en) 1979-10-01 1985-10-29 Mobil Oil Corporation Conversion of coal to electricity
US4370518A (en) 1979-12-03 1983-01-25 Hughes Tool Company Splice for lead-coated and insulated conductors
US4250230A (en) 1979-12-10 1981-02-10 In Situ Technology, Inc. Generating electricity from coal in situ
US4250962A (en) 1979-12-14 1981-02-17 Gulf Research & Development Company In situ combustion process for the recovery of liquid carbonaceous fuels from subterranean formations
US4359687A (en) 1980-01-25 1982-11-16 Shell Oil Company Method and apparatus for determining shaliness and oil saturations in earth formations using induced polarization in the frequency domain
US4398151A (en) 1980-01-25 1983-08-09 Shell Oil Company Method for correcting an electrical log for the presence of shale in a formation
US4285547A (en) 1980-02-01 1981-08-25 Multi Mineral Corporation Integrated in situ shale oil and mineral recovery process
USRE30738E (en) 1980-02-06 1981-09-08 Iit Research Institute Apparatus and method for in situ heat processing of hydrocarbonaceous formations
US4303126A (en) 1980-02-27 1981-12-01 Chevron Research Company Arrangement of wells for producing subsurface viscous petroleum
US4477376A (en) 1980-03-10 1984-10-16 Gold Marvin H Castable mixture for insulating spliced high voltage cable
US4445574A (en) 1980-03-24 1984-05-01 Geo Vann, Inc. Continuous borehole formed horizontally through a hydrocarbon producing formation
US4417782A (en) 1980-03-31 1983-11-29 Raychem Corporation Fiber optic temperature sensing
CA1168283A (en) 1980-04-14 1984-05-29 Hiroshi Teratani Electrode device for electrically heating underground deposits of hydrocarbons
JPS56146588A (en) * 1980-04-14 1981-11-14 Mitsubishi Electric Corp Electric heating electrode device for hydrocarbon based underground resources
US4273188A (en) 1980-04-30 1981-06-16 Gulf Research & Development Company In situ combustion process for the recovery of liquid carbonaceous fuels from subterranean formations
US4317485A (en) * 1980-05-23 1982-03-02 Baker International Corporation Pump catcher apparatus
US4306621A (en) 1980-05-23 1981-12-22 Boyd R Michael Method for in situ coal gasification operations
US4409090A (en) 1980-06-02 1983-10-11 University Of Utah Process for recovering products from tar sand
CA1165361A (en) 1980-06-03 1984-04-10 Toshiyuki Kobayashi Electrode unit for electrically heating underground hydrocarbon deposits
JPS6015109B2 (ja) * 1980-06-03 1985-04-17 三菱電機株式会社 炭化水素系地下資源の電気加熱用電極装置
US4381641A (en) 1980-06-23 1983-05-03 Gulf Research & Development Company Substoichiometric combustion of low heating value gases
US4401099A (en) 1980-07-11 1983-08-30 W.B. Combustion, Inc. Single-ended recuperative radiant tube assembly and method
US4299285A (en) 1980-07-21 1981-11-10 Gulf Research & Development Company Underground gasification of bituminous coal
DE3030110C2 (de) 1980-08-08 1983-04-21 Vsesojuznyj neftegazovyj naučno-issledovatel'skij institut, Moskva Verfahren zur Gewinnung von Erdöl durch Grubenbaue und durch Wärmezufuhr
US4396062A (en) 1980-10-06 1983-08-02 University Of Utah Research Foundation Apparatus and method for time-domain tracking of high-speed chemical reactions
US4353418A (en) 1980-10-20 1982-10-12 Standard Oil Company (Indiana) In situ retorting of oil shale
US4384613A (en) 1980-10-24 1983-05-24 Terra Tek, Inc. Method of in-situ retorting of carbonaceous material for recovery of organic liquids and gases
US4366864A (en) 1980-11-24 1983-01-04 Exxon Research And Engineering Co. Method for recovery of hydrocarbons from oil-bearing limestone or dolomite
US4401163A (en) 1980-12-29 1983-08-30 The Standard Oil Company Modified in situ retorting of oil shale
JPS57116891A (en) * 1980-12-30 1982-07-21 Kobe Steel Ltd Method of and apparatus for generating steam on shaft bottom
US4385661A (en) 1981-01-07 1983-05-31 The United States Of America As Represented By The United States Department Of Energy Downhole steam generator with improved preheating, combustion and protection features
US4448251A (en) 1981-01-08 1984-05-15 Uop Inc. In situ conversion of hydrocarbonaceous oil
JPS57116891U (ru) 1981-01-12 1982-07-20
US4423311A (en) 1981-01-19 1983-12-27 Varney Sr Paul Electric heating apparatus for de-icing pipes
US4333764A (en) 1981-01-21 1982-06-08 Shell Oil Company Nitrogen-gas-stabilized cement and a process for making and using it
US4366668A (en) 1981-02-25 1983-01-04 Gulf Research & Development Company Substoichiometric combustion of low heating value gases
US4382469A (en) 1981-03-10 1983-05-10 Electro-Petroleum, Inc. Method of in situ gasification
US4363361A (en) 1981-03-19 1982-12-14 Gulf Research & Development Company Substoichiometric combustion of low heating value gases
US4390067A (en) 1981-04-06 1983-06-28 Exxon Production Research Co. Method of treating reservoirs containing very viscous crude oil or bitumen
US4399866A (en) 1981-04-10 1983-08-23 Atlantic Richfield Company Method for controlling the flow of subterranean water into a selected zone in a permeable subterranean carbonaceous deposit
US4444255A (en) 1981-04-20 1984-04-24 Lloyd Geoffrey Apparatus and process for the recovery of oil
US4380930A (en) 1981-05-01 1983-04-26 Mobil Oil Corporation System for transmitting ultrasonic energy through core samples
US4429745A (en) 1981-05-08 1984-02-07 Mobil Oil Corporation Oil recovery method
US4378048A (en) 1981-05-08 1983-03-29 Gulf Research & Development Company Substoichiometric combustion of low heating value gases using different platinum catalysts
US4384614A (en) 1981-05-11 1983-05-24 Justheim Pertroleum Company Method of retorting oil shale by velocity flow of super-heated air
US4403110A (en) 1981-05-15 1983-09-06 Walter Kidde And Company, Inc. Electrical cable splice
US4437519A (en) 1981-06-03 1984-03-20 Occidental Oil Shale, Inc. Reduction of shale oil pour point
US4368452A (en) 1981-06-22 1983-01-11 Kerr Jr Robert L Thermal protection of aluminum conductor junctions
US4428700A (en) 1981-08-03 1984-01-31 E. R. Johnson Associates, Inc. Method for disposing of waste materials
US4456065A (en) 1981-08-20 1984-06-26 Elektra Energie A.G. Heavy oil recovering
US4344483A (en) 1981-09-08 1982-08-17 Fisher Charles B Multiple-site underground magnetic heating of hydrocarbons
US4452491A (en) 1981-09-25 1984-06-05 Intercontinental Econergy Associates, Inc. Recovery of hydrocarbons from deep underground deposits of tar sands
US4425967A (en) * 1981-10-07 1984-01-17 Standard Oil Company (Indiana) Ignition procedure and process for in situ retorting of oil shale
US4605680A (en) 1981-10-13 1986-08-12 Chevron Research Company Conversion of synthesis gas to diesel fuel and gasoline
US4401162A (en) 1981-10-13 1983-08-30 Synfuel (An Indiana Limited Partnership) In situ oil shale process
US4410042A (en) 1981-11-02 1983-10-18 Mobil Oil Corporation In-situ combustion method for recovery of heavy oil utilizing oxygen and carbon dioxide as initial oxidant
US4549073A (en) 1981-11-06 1985-10-22 Oximetrix, Inc. Current controller for resistive heating element
US4444258A (en) 1981-11-10 1984-04-24 Nicholas Kalmar In situ recovery of oil from oil shale
US4418752A (en) 1982-01-07 1983-12-06 Conoco Inc. Thermal oil recovery with solvent recirculation
FR2519688A1 (fr) 1982-01-08 1983-07-18 Elf Aquitaine Systeme d'etancheite pour puits de forage dans lequel circule un fluide chaud
US4397732A (en) 1982-02-11 1983-08-09 International Coal Refining Company Process for coal liquefaction employing selective coal feed
GB2117030B (en) 1982-03-17 1985-09-11 Cameron Iron Works Inc Method and apparatus for remote installations of dual tubing strings in a subsea well
US4530401A (en) 1982-04-05 1985-07-23 Mobil Oil Corporation Method for maximum in-situ visbreaking of heavy oil
CA1196594A (en) 1982-04-08 1985-11-12 Guy Savard Recovery of oil from tar sands
US4537252A (en) 1982-04-23 1985-08-27 Standard Oil Company (Indiana) Method of underground conversion of coal
US4491179A (en) 1982-04-26 1985-01-01 Pirson Sylvain J Method for oil recovery by in situ exfoliation drive
US4455215A (en) 1982-04-29 1984-06-19 Jarrott David M Process for the geoconversion of coal into oil
US4415034A (en) 1982-05-03 1983-11-15 Cities Service Company Electrode well completion
US4412585A (en) 1982-05-03 1983-11-01 Cities Service Company Electrothermal process for recovering hydrocarbons
US4524826A (en) 1982-06-14 1985-06-25 Texaco Inc. Method of heating an oil shale formation
US4457374A (en) 1982-06-29 1984-07-03 Standard Oil Company Transient response process for detecting in situ retorting conditions
US4442896A (en) 1982-07-21 1984-04-17 Reale Lucio V Treatment of underground beds
US4407973A (en) 1982-07-28 1983-10-04 The M. W. Kellogg Company Methanol from coal and natural gas
US4449594A (en) 1982-07-30 1984-05-22 Allied Corporation Method for obtaining pressurized core samples from underpressurized reservoirs
US4479541A (en) 1982-08-23 1984-10-30 Wang Fun Den Method and apparatus for recovery of oil, gas and mineral deposits by panel opening
US4460044A (en) 1982-08-31 1984-07-17 Chevron Research Company Advancing heated annulus steam drive
US4544478A (en) 1982-09-03 1985-10-01 Chevron Research Company Process for pyrolyzing hydrocarbonaceous solids to recover volatile hydrocarbons
US4463988A (en) 1982-09-07 1984-08-07 Cities Service Co. Horizontal heated plane process
US4458767A (en) 1982-09-28 1984-07-10 Mobil Oil Corporation Method for directionally drilling a first well to intersect a second well
US4485868A (en) 1982-09-29 1984-12-04 Iit Research Institute Method for recovery of viscous hydrocarbons by electromagnetic heating in situ
US4927857A (en) 1982-09-30 1990-05-22 Engelhard Corporation Method of methanol production
US4695713A (en) 1982-09-30 1987-09-22 Metcal, Inc. Autoregulating, electrically shielded heater
CA1214815A (en) 1982-09-30 1986-12-02 John F. Krumme Autoregulating electrically shielded heater
US4498531A (en) 1982-10-01 1985-02-12 Rockwell International Corporation Emission controller for indirect fired downhole steam generators
US4485869A (en) 1982-10-22 1984-12-04 Iit Research Institute Recovery of liquid hydrocarbons from oil shale by electromagnetic heating in situ
EP0110449B1 (en) 1982-11-22 1986-08-13 Shell Internationale Researchmaatschappij B.V. Process for the preparation of a fischer-tropsch catalyst, a catalyst so prepared and use of this catalyst in the preparation of hydrocarbons
US4474238A (en) 1982-11-30 1984-10-02 Phillips Petroleum Company Method and apparatus for treatment of subsurface formations
US4498535A (en) 1982-11-30 1985-02-12 Iit Research Institute Apparatus and method for in situ controlled heat processing of hydrocarbonaceous formations with a controlled parameter line
US4752673A (en) 1982-12-01 1988-06-21 Metcal, Inc. Autoregulating heater
US4520229A (en) 1983-01-03 1985-05-28 Amerace Corporation Splice connector housing and assembly of cables employing same
US4501326A (en) 1983-01-17 1985-02-26 Gulf Canada Limited In-situ recovery of viscous hydrocarbonaceous crude oil
US4609041A (en) 1983-02-10 1986-09-02 Magda Richard M Well hot oil system
US4640352A (en) 1983-03-21 1987-02-03 Shell Oil Company In-situ steam drive oil recovery process
US4886118A (en) 1983-03-21 1989-12-12 Shell Oil Company Conductively heating a subterranean oil shale to create permeability and subsequently produce oil
US4458757A (en) 1983-04-25 1984-07-10 Exxon Research And Engineering Co. In situ shale-oil recovery process
US4545435A (en) 1983-04-29 1985-10-08 Iit Research Institute Conduction heating of hydrocarbonaceous formations
US4524827A (en) 1983-04-29 1985-06-25 Iit Research Institute Single well stimulation for the recovery of liquid hydrocarbons from subsurface formations
US4518548A (en) 1983-05-02 1985-05-21 Sulcon, Inc. Method of overlaying sulphur concrete on horizontal and vertical surfaces
US4470459A (en) 1983-05-09 1984-09-11 Halliburton Company Apparatus and method for controlled temperature heating of volumes of hydrocarbonaceous materials in earth formations
EP0130671A3 (en) 1983-05-26 1986-12-17 Metcal Inc. Multiple temperature autoregulating heater
US5073625A (en) 1983-05-26 1991-12-17 Metcal, Inc. Self-regulating porous heating device
US4794226A (en) 1983-05-26 1988-12-27 Metcal, Inc. Self-regulating porous heater device
DE3319732A1 (de) 1983-05-31 1984-12-06 Kraftwerk Union AG, 4330 Mülheim Mittellastkraftwerk mit integrierter kohlevergasungsanlage zur erzeugung von strom und methanol
US4583046A (en) 1983-06-20 1986-04-15 Shell Oil Company Apparatus for focused electrode induced polarization logging
US4658215A (en) 1983-06-20 1987-04-14 Shell Oil Company Method for induced polarization logging
US4717814A (en) 1983-06-27 1988-01-05 Metcal, Inc. Slotted autoregulating heater
US4439307A (en) 1983-07-01 1984-03-27 Dravo Corporation Heating process gas for indirect shale oil retorting through the combustion of residual carbon in oil depleted shale
US4985313A (en) 1985-01-14 1991-01-15 Raychem Limited Wire and cable
US5209987A (en) 1983-07-08 1993-05-11 Raychem Limited Wire and cable
US4598392A (en) 1983-07-26 1986-07-01 Mobil Oil Corporation Vibratory signal sweep seismic prospecting method and apparatus
US4501445A (en) 1983-08-01 1985-02-26 Cities Service Company Method of in-situ hydrogenation of carbonaceous material
US4538682A (en) 1983-09-08 1985-09-03 Mcmanus James W Method and apparatus for removing oil well paraffin
US4698149A (en) 1983-11-07 1987-10-06 Mobil Oil Corporation Enhanced recovery of hydrocarbonaceous fluids oil shale
US4573530A (en) 1983-11-07 1986-03-04 Mobil Oil Corporation In-situ gasification of tar sands utilizing a combustible gas
US4489782A (en) 1983-12-12 1984-12-25 Atlantic Richfield Company Viscous oil production using electrical current heating and lateral drain holes
US4598772A (en) 1983-12-28 1986-07-08 Mobil Oil Corporation Method for operating a production well in an oxygen driven in-situ combustion oil recovery process
US4613754A (en) 1983-12-29 1986-09-23 Shell Oil Company Tomographic calibration apparatus
US4635197A (en) 1983-12-29 1987-01-06 Shell Oil Company High resolution tomographic imaging method
US4540882A (en) 1983-12-29 1985-09-10 Shell Oil Company Method of determining drilling fluid invasion
US4571491A (en) 1983-12-29 1986-02-18 Shell Oil Company Method of imaging the atomic number of a sample
US4583242A (en) 1983-12-29 1986-04-15 Shell Oil Company Apparatus for positioning a sample in a computerized axial tomographic scanner
US4542648A (en) 1983-12-29 1985-09-24 Shell Oil Company Method of correlating a core sample with its original position in a borehole
US4662439A (en) 1984-01-20 1987-05-05 Amoco Corporation Method of underground conversion of coal
US4623401A (en) 1984-03-06 1986-11-18 Metcal, Inc. Heat treatment with an autoregulating heater
US4644283A (en) 1984-03-19 1987-02-17 Shell Oil Company In-situ method for determining pore size distribution, capillary pressure and permeability
US4552214A (en) 1984-03-22 1985-11-12 Standard Oil Company (Indiana) Pulsed in situ retorting in an array of oil shale retorts
US4637464A (en) * 1984-03-22 1987-01-20 Amoco Corporation In situ retorting of oil shale with pulsed water purge
US4570715A (en) 1984-04-06 1986-02-18 Shell Oil Company Formation-tailored method and apparatus for uniformly heating long subterranean intervals at high temperature
US4577690A (en) 1984-04-18 1986-03-25 Mobil Oil Corporation Method of using seismic data to monitor firefloods
US4592423A (en) 1984-05-14 1986-06-03 Texaco Inc. Hydrocarbon stratum retorting means and method
US4597441A (en) 1984-05-25 1986-07-01 World Energy Systems, Inc. Recovery of oil by in situ hydrogenation
US4620592A (en) 1984-06-11 1986-11-04 Atlantic Richfield Company Progressive sequence for viscous oil recovery
US4663711A (en) 1984-06-22 1987-05-05 Shell Oil Company Method of analyzing fluid saturation using computerized axial tomography
US4577503A (en) 1984-09-04 1986-03-25 International Business Machines Corporation Method and device for detecting a specific acoustic spectral feature
US4577691A (en) 1984-09-10 1986-03-25 Texaco Inc. Method and apparatus for producing viscous hydrocarbons from a subterranean formation
US4576231A (en) 1984-09-13 1986-03-18 Texaco Inc. Method and apparatus for combating encroachment by in situ treated formations
US4597444A (en) 1984-09-21 1986-07-01 Atlantic Richfield Company Method for excavating a large diameter shaft into the earth and at least partially through an oil-bearing formation
US4691771A (en) 1984-09-25 1987-09-08 Worldenergy Systems, Inc. Recovery of oil by in-situ combustion followed by in-situ hydrogenation
JPS6177795A (ja) * 1984-09-26 1986-04-21 株式会社東芝 原子炉用制御棒
US4616705A (en) 1984-10-05 1986-10-14 Shell Oil Company Mini-well temperature profiling process
JPS61102990A (ja) * 1984-10-24 1986-05-21 近畿イシコ株式会社 基礎工事用機械の昇降装置
US4598770A (en) 1984-10-25 1986-07-08 Mobil Oil Corporation Thermal recovery method for viscous oil
US4572299A (en) 1984-10-30 1986-02-25 Shell Oil Company Heater cable installation
JPS61118692A (ja) * 1984-11-13 1986-06-05 ウエスチングハウス　エレクトリック　コ−ポレ−ション 加圧水型原子炉発電システムの運転方法
US4634187A (en) 1984-11-21 1987-01-06 Isl Ventures, Inc. Method of in-situ leaching of ores
US4669542A (en) 1984-11-21 1987-06-02 Mobil Oil Corporation Simultaneous recovery of crude from multiple zones in a reservoir
US4585066A (en) 1984-11-30 1986-04-29 Shell Oil Company Well treating process for installing a cable bundle containing strands of changing diameter
US4704514A (en) 1985-01-11 1987-11-03 Egmond Cor F Van Heating rate variant elongated electrical resistance heater
US4614392A (en) 1985-01-15 1986-09-30 Moore Boyd B Well bore electric pump power cable connector for multiple individual, insulated conductors of a pump power cable
US4645906A (en) 1985-03-04 1987-02-24 Thermon Manufacturing Company Reduced resistance skin effect heat generating system
US4643256A (en) 1985-03-18 1987-02-17 Shell Oil Company Steam-foaming surfactant mixtures which are tolerant of divalent ions
US4698583A (en) 1985-03-26 1987-10-06 Raychem Corporation Method of monitoring a heater for faults
US4785163A (en) 1985-03-26 1988-11-15 Raychem Corporation Method for monitoring a heater
US4670634A (en) 1985-04-05 1987-06-02 Iit Research Institute In situ decontamination of spills and landfills by radio frequency heating
FI861646A (fi) 1985-04-19 1986-10-20 Raychem Gmbh Vaermningsanordning.
US4601333A (en) * 1985-04-29 1986-07-22 Hughes Tool Company Thermal slide joint
JPS61282594A (ja) 1985-06-05 1986-12-12 日本海洋掘削株式会社 ストリングスの測長方法
US4671102A (en) 1985-06-18 1987-06-09 Shell Oil Company Method and apparatus for determining distribution of fluids
US4626665A (en) 1985-06-24 1986-12-02 Shell Oil Company Metal oversheathed electrical resistance heater
US4623444A (en) 1985-06-27 1986-11-18 Occidental Oil Shale, Inc. Upgrading shale oil by a combination process
US4605489A (en) 1985-06-27 1986-08-12 Occidental Oil Shale, Inc. Upgrading shale oil by a combination process
US4662438A (en) 1985-07-19 1987-05-05 Uentech Corporation Method and apparatus for enhancing liquid hydrocarbon production from a single borehole in a slowly producing formation by non-uniform heating through optimized electrode arrays surrounding the borehole
US4728892A (en) 1985-08-13 1988-03-01 Shell Oil Company NMR imaging of materials
US4719423A (en) 1985-08-13 1988-01-12 Shell Oil Company NMR imaging of materials for transport properties
NO853394L (no) * 1985-08-29 1987-03-02 You Yi Tu Anordning for aa sperre et borehull ved boring etter oljekilder e.l.
US4778586A (en) 1985-08-30 1988-10-18 Resource Technology Associates Viscosity reduction processing at elevated pressure
US4662437A (en) 1985-11-14 1987-05-05 Atlantic Richfield Company Electrically stimulated well production system with flexible tubing conductor
CA1253555A (en) 1985-11-21 1989-05-02 Cornelis F.H. Van Egmond Heating rate variant elongated electrical resistance heater
US4662443A (en) 1985-12-05 1987-05-05 Amoco Corporation Combination air-blown and oxygen-blown underground coal gasification process
US4849611A (en) 1985-12-16 1989-07-18 Raychem Corporation Self-regulating heater employing reactive components
US4730162A (en) 1985-12-31 1988-03-08 Shell Oil Company Time-domain induced polarization logging method and apparatus with gated amplification level
US4706751A (en) 1986-01-31 1987-11-17 S-Cal Research Corp. Heavy oil recovery process
US4694907A (en) 1986-02-21 1987-09-22 Carbotek, Inc. Thermally-enhanced oil recovery method and apparatus
US4640353A (en) 1986-03-21 1987-02-03 Atlantic Richfield Company Electrode well and method of completion
US4734115A (en) 1986-03-24 1988-03-29 Air Products And Chemicals, Inc. Low pressure process for C3+ liquids recovery from process product gas
US4793421A (en) * 1986-04-08 1988-12-27 Becor Western Inc. Programmed automatic drill control
US4651825A (en) 1986-05-09 1987-03-24 Atlantic Richfield Company Enhanced well production
GB2190162A (en) * 1986-05-09 1987-11-11 Kawasaki Thermal Systems Inc Thermally insulated telescopic pipe coupling
US4814587A (en) 1986-06-10 1989-03-21 Metcal, Inc. High power self-regulating heater
US4682652A (en) 1986-06-30 1987-07-28 Texaco Inc. Producing hydrocarbons through successively perforated intervals of a horizontal well between two vertical wells
US4769602A (en) 1986-07-02 1988-09-06 Shell Oil Company Determining multiphase saturations by NMR imaging of multiple nuclides
US4893504A (en) 1986-07-02 1990-01-16 Shell Oil Company Method for determining capillary pressure and relative permeability by imaging
US4716960A (en) 1986-07-14 1988-01-05 Production Technologies International, Inc. Method and system for introducing electric current into a well
US4818370A (en) 1986-07-23 1989-04-04 Cities Service Oil And Gas Corporation Process for converting heavy crudes, tars, and bitumens to lighter products in the presence of brine at supercritical conditions
US4772634A (en) 1986-07-31 1988-09-20 Energy Research Corporation Apparatus and method for methanol production using a fuel cell to regulate the gas composition entering the methanol synthesizer
US4744245A (en) 1986-08-12 1988-05-17 Atlantic Richfield Company Acoustic measurements in rock formations for determining fracture orientation
US4696345A (en) 1986-08-21 1987-09-29 Chevron Research Company Hasdrive with multiple offset producers
US4769606A (en) 1986-09-30 1988-09-06 Shell Oil Company Induced polarization method and apparatus for distinguishing dispersed and laminated clay in earth formations
US5043668A (en) * 1987-08-26 1991-08-27 Paramagnetic Logging Inc. Methods and apparatus for measurement of electronic properties of geological formations through borehole casing
US5340467A (en) 1986-11-24 1994-08-23 Canadian Occidental Petroleum Ltd. Process for recovery of hydrocarbons and rejection of sand
US4983319A (en) 1986-11-24 1991-01-08 Canadian Occidental Petroleum Ltd. Preparation of low-viscosity improved stable crude oil transport emulsions
US5316664A (en) 1986-11-24 1994-05-31 Canadian Occidental Petroleum, Ltd. Process for recovery of hydrocarbons and rejection of sand
CA1288043C (en) 1986-12-15 1991-08-27 Peter Van Meurs Conductively heating a subterranean oil shale to create permeabilityand subsequently produce oil
US4766958A (en) 1987-01-12 1988-08-30 Mobil Oil Corporation Method of recovering viscous oil from reservoirs with multiple horizontal zones
US4756367A (en) 1987-04-28 1988-07-12 Amoco Corporation Method for producing natural gas from a coal seam
US4817711A (en) 1987-05-27 1989-04-04 Jeambey Calhoun G System for recovery of petroleum from petroleum impregnated media
US4818371A (en) 1987-06-05 1989-04-04 Resource Technology Associates Viscosity reduction by direct oxidative heating
US4787452A (en) 1987-06-08 1988-11-29 Mobil Oil Corporation Disposal of produced formation fines during oil recovery
US4821798A (en) 1987-06-09 1989-04-18 Ors Development Corporation Heating system for rathole oil well
US4793409A (en) 1987-06-18 1988-12-27 Ors Development Corporation Method and apparatus for forming an insulated oil well casing
US4856341A (en) 1987-06-25 1989-08-15 Shell Oil Company Apparatus for analysis of failure of material
US4884455A (en) 1987-06-25 1989-12-05 Shell Oil Company Method for analysis of failure of material employing imaging
US4827761A (en) 1987-06-25 1989-05-09 Shell Oil Company Sample holder
US4776638A (en) 1987-07-13 1988-10-11 University Of Kentucky Research Foundation Method and apparatus for conversion of coal in situ
US4848924A (en) 1987-08-19 1989-07-18 The Babcock & Wilcox Company Acoustic pyrometer
US4828031A (en) 1987-10-13 1989-05-09 Chevron Research Company In situ chemical stimulation of diatomite formations
US4762425A (en) 1987-10-15 1988-08-09 Parthasarathy Shakkottai System for temperature profile measurement in large furnances and kilns and method therefor
US4815791A (en) 1987-10-22 1989-03-28 The United States Of America As Represented By The Secretary Of The Interior Bedded mineral extraction process
US5306640A (en) 1987-10-28 1994-04-26 Shell Oil Company Method for determining preselected properties of a crude oil
US4987368A (en) * 1987-11-05 1991-01-22 Shell Oil Company Nuclear magnetism logging tool using high-temperature superconducting squid detectors
US4842448A (en) 1987-11-12 1989-06-27 Drexel University Method of removing contaminants from contaminated soil in situ
US4808925A (en) 1987-11-19 1989-02-28 Halliburton Company Three magnet casing collar locator
US4823890A (en) 1988-02-23 1989-04-25 Longyear Company Reverse circulation bit apparatus
US4883582A (en) 1988-03-07 1989-11-28 Mccants Malcolm T Vis-breaking heavy crude oils for pumpability
US4866983A (en) 1988-04-14 1989-09-19 Shell Oil Company Analytical methods and apparatus for measuring the oil content of sponge core
US4885080A (en) 1988-05-25 1989-12-05 Phillips Petroleum Company Process for demetallizing and desulfurizing heavy crude oil
US5046560A (en) 1988-06-10 1991-09-10 Exxon Production Research Company Oil recovery process using arkyl aryl polyalkoxyol sulfonate surfactants as mobility control agents
US4884635A (en) * 1988-08-24 1989-12-05 Texaco Canada Resources Enhanced oil recovery with a mixture of water and aromatic hydrocarbons
US4842070A (en) 1988-09-15 1989-06-27 Amoco Corporation Procedure for improving reservoir sweep efficiency using paraffinic or asphaltic hydrocarbons
US4928765A (en) 1988-09-27 1990-05-29 Ramex Syn-Fuels International Method and apparatus for shale gas recovery
GB8824111D0 (en) 1988-10-14 1988-11-23 Nashcliffe Ltd Shaft excavation system
US4856587A (en) 1988-10-27 1989-08-15 Nielson Jay P Recovery of oil from oil-bearing formation by continually flowing pressurized heated gas through channel alongside matrix
US5064006A (en) 1988-10-28 1991-11-12 Magrange, Inc Downhole combination tool
US4848460A (en) 1988-11-04 1989-07-18 Western Research Institute Contained recovery of oily waste
US5065501A (en) 1988-11-29 1991-11-19 Amp Incorporated Generating electromagnetic fields in a self regulating temperature heater by positioning of a current return bus
US4859200A (en) 1988-12-05 1989-08-22 Baker Hughes Incorporated Downhole electrical connector for submersible pump
US4860544A (en) 1988-12-08 1989-08-29 Concept R.K.K. Limited Closed cryogenic barrier for containment of hazardous material migration in the earth
US4974425A (en) 1988-12-08 1990-12-04 Concept Rkk, Limited Closed cryogenic barrier for containment of hazardous material migration in the earth
US4933640A (en) 1988-12-30 1990-06-12 Vector Magnetics Apparatus for locating an elongated conductive body by electromagnetic measurement while drilling
US4940095A (en) 1989-01-27 1990-07-10 Dowell Schlumberger Incorporated Deployment/retrieval method and apparatus for well tools used with coiled tubing
US5103920A (en) 1989-03-01 1992-04-14 Patton Consulting Inc. Surveying system and method for locating target subterranean bodies
JPH04506564A (ja) * 1989-03-13 1992-11-12 ユニヴァーシティ　オブ　ユタ　リサーチ　ファウンデーション 電力発生方法及び装置
CA2015318C (en) 1990-04-24 1994-02-08 Jack E. Bridges Power sources for downhole electrical heating
US4895206A (en) 1989-03-16 1990-01-23 Price Ernest H Pulsed in situ exothermic shock wave and retorting process for hydrocarbon recovery and detoxification of selected wastes
US4913065A (en) 1989-03-27 1990-04-03 Indugas, Inc. In situ thermal waste disposal system
US4947672A (en) 1989-04-03 1990-08-14 Burndy Corporation Hydraulic compression tool having an improved relief and release valve
NL8901138A (nl) 1989-05-03 1990-12-03 Nkf Kabel Bv Insteekverbinding voor hoogspanningskunststofkabels.
US4959193A (en) * 1989-05-11 1990-09-25 General Electric Company Indirect passive cooling system for liquid metal cooled nuclear reactors
DE3918265A1 (de) 1989-06-05 1991-01-03 Henkel Kgaa Verfahren zur herstellung von tensidgemischen auf ethersulfonatbasis und ihre verwendung
US5059303A (en) 1989-06-16 1991-10-22 Amoco Corporation Oil stabilization
US5041210A (en) 1989-06-30 1991-08-20 Marathon Oil Company Oil shale retorting with steam and produced gas
DE3922612C2 (de) 1989-07-10 1998-07-02 Krupp Koppers Gmbh Verfahren zur Erzeugung von Methanol-Synthesegas
US4982786A (en) 1989-07-14 1991-01-08 Mobil Oil Corporation Use of CO2 /steam to enhance floods in horizontal wellbores
US5050386A (en) 1989-08-16 1991-09-24 Rkk, Limited Method and apparatus for containment of hazardous material migration in the earth
US5097903A (en) 1989-09-22 1992-03-24 Jack C. Sloan Method for recovering intractable petroleum from subterranean formations
US5305239A (en) 1989-10-04 1994-04-19 The Texas A&M University System Ultrasonic non-destructive evaluation of thin specimens
US4926941A (en) 1989-10-10 1990-05-22 Shell Oil Company Method of producing tar sand deposits containing conductive layers
US4984594A (en) * 1989-10-27 1991-01-15 Shell Oil Company Vacuum method for removing soil contamination utilizing surface electrical heating
US5656239A (en) 1989-10-27 1997-08-12 Shell Oil Company Method for recovering contaminants from soil utilizing electrical heating
US4986375A (en) 1989-12-04 1991-01-22 Maher Thomas P Device for facilitating drill bit retrieval
US5336851A (en) * 1989-12-27 1994-08-09 Sumitomo Electric Industries, Ltd. Insulated electrical conductor wire having a high operating temperature
US5082055A (en) 1990-01-24 1992-01-21 Indugas, Inc. Gas fired radiant tube heater
US5020596A (en) 1990-01-24 1991-06-04 Indugas, Inc. Enhanced oil recovery system with a radiant tube heater
US5011329A (en) 1990-02-05 1991-04-30 Hrubetz Exploration Company In situ soil decontamination method and apparatus
CA2009782A1 (en) 1990-02-12 1991-08-12 Anoosh I. Kiamanesh In-situ tuned microwave oil extraction process
TW215446B (ru) 1990-02-23 1993-11-01 Furukawa Electric Co Ltd
US5152341A (en) 1990-03-09 1992-10-06 Raymond S. Kasevich Electromagnetic method and apparatus for the decontamination of hazardous material-containing volumes
US5027896A (en) 1990-03-21 1991-07-02 Anderson Leonard M Method for in-situ recovery of energy raw material by the introduction of a water/oxygen slurry
GB9007147D0 (en) 1990-03-30 1990-05-30 Framo Dev Ltd Thermal mineral extraction system
CA2015460C (en) 1990-04-26 1993-12-14 Kenneth Edwin Kisman Process for confining steam injected into a heavy oil reservoir
US5126037A (en) 1990-05-04 1992-06-30 Union Oil Company Of California Geopreater heating method and apparatus
US5032042A (en) 1990-06-26 1991-07-16 New Jersey Institute Of Technology Method and apparatus for eliminating non-naturally occurring subsurface, liquid toxic contaminants from soil
US5201219A (en) 1990-06-29 1993-04-13 Amoco Corporation Method and apparatus for measuring free hydrocarbons and hydrocarbons potential from whole core
US5054551A (en) 1990-08-03 1991-10-08 Chevron Research And Technology Company In-situ heated annulus refining process
US5109928A (en) 1990-08-17 1992-05-05 Mccants Malcolm T Method for production of hydrocarbon diluent from heavy crude oil
US5060726A (en) 1990-08-23 1991-10-29 Shell Oil Company Method and apparatus for producing tar sand deposits containing conductive layers having little or no vertical communication
US5042579A (en) 1990-08-23 1991-08-27 Shell Oil Company Method and apparatus for producing tar sand deposits containing conductive layers
US5046559A (en) 1990-08-23 1991-09-10 Shell Oil Company Method and apparatus for producing hydrocarbon bearing deposits in formations having shale layers
BR9004240A (pt) 1990-08-28 1992-03-24 Petroleo Brasileiro Sa Processo de aquecimento eletrico de tubulacoes
US5085276A (en) 1990-08-29 1992-02-04 Chevron Research And Technology Company Production of oil from low permeability formations by sequential steam fracturing
US5245161A (en) 1990-08-31 1993-09-14 Tokyo Kogyo Boyeki Shokai, Ltd. Electric heater
US5066852A (en) 1990-09-17 1991-11-19 Teledyne Ind. Inc. Thermoplastic end seal for electric heating elements
US5207273A (en) 1990-09-17 1993-05-04 Production Technologies International Inc. Method and apparatus for pumping wells
JPH04272680A (ja) 1990-09-20 1992-09-29 Thermon Mfg Co スイッチ制御形ゾーン式加熱ケーブル及びその組み立て方法
US5182427A (en) 1990-09-20 1993-01-26 Metcal, Inc. Self-regulating heater utilizing ferrite-type body
US5517593A (en) 1990-10-01 1996-05-14 John Nenniger Control system for well stimulation apparatus with response time temperature rise used in determining heater control temperature setpoint
US5400430A (en) 1990-10-01 1995-03-21 Nenniger; John E. Method for injection well stimulation
JPH0827387B2 (ja) * 1990-10-05 1996-03-21 動力炉・核燃料開発事業団 耐熱高速中性子遮蔽材
US5408047A (en) 1990-10-25 1995-04-18 Minnesota Mining And Manufacturing Company Transition joint for oil-filled cables
US5070533A (en) 1990-11-07 1991-12-03 Uentech Corporation Robust electrical heating systems for mineral wells
FR2669077B2 (fr) 1990-11-09 1995-02-03 Institut Francais Petrole Methode et dispositif pour effectuer des interventions dans des puits ou regnent des temperatures elevees.
US5065818A (en) 1991-01-07 1991-11-19 Shell Oil Company Subterranean heaters
US5060287A (en) 1990-12-04 1991-10-22 Shell Oil Company Heater utilizing copper-nickel alloy core
US5217076A (en) 1990-12-04 1993-06-08 Masek John A Method and apparatus for improved recovery of oil from porous, subsurface deposits (targevcir oricess)
US5190405A (en) 1990-12-14 1993-03-02 Shell Oil Company Vacuum method for removing soil contaminants utilizing thermal conduction heating
SU1836876A3 (ru) 1990-12-29 1994-12-30 Смешанное научно-техническое товарищество по разработке техники и технологии для подземной электроэнергетики Способ отработки угольных пластов и комплекс оборудования для его осуществления
US5667008A (en) 1991-02-06 1997-09-16 Quick Connectors, Inc. Seal electrical conductor arrangement for use with a well bore in hazardous areas
US5289882A (en) 1991-02-06 1994-03-01 Boyd B. Moore Sealed electrical conductor method and arrangement for use with a well bore in hazardous areas
US5103909A (en) 1991-02-19 1992-04-14 Shell Oil Company Profile control in enhanced oil recovery
US5261490A (en) 1991-03-18 1993-11-16 Nkk Corporation Method for dumping and disposing of carbon dioxide gas and apparatus therefor
US5204270A (en) 1991-04-29 1993-04-20 Lacount Robert B Multiple sample characterization of coals and other substances by controlled-atmosphere programmed temperature oxidation
US5246273A (en) 1991-05-13 1993-09-21 Rosar Edward C Method and apparatus for solution mining
CA2043092A1 (en) 1991-05-23 1992-11-24 Bruce C. W. Mcgee Electrical heating of oil reservoir
US5117912A (en) 1991-05-24 1992-06-02 Marathon Oil Company Method of positioning tubing within a horizontal well
ATE147135T1 (de) 1991-06-17 1997-01-15 Electric Power Res Inst Energieanlage mit komprimiertem luftspeicher
DK0519573T3 (da) 1991-06-21 1995-07-03 Shell Int Research Hydrogenerings-katalysator og fremgangsmåde
IT1248535B (it) 1991-06-24 1995-01-19 Cise Spa Sistema per misurare il tempo di trasferimento di un'onda sonora
US5133406A (en) 1991-07-05 1992-07-28 Amoco Corporation Generating oxygen-depleted air useful for increasing methane production
US5189283A (en) 1991-08-28 1993-02-23 Shell Oil Company Current to power crossover heater control
US5168927A (en) 1991-09-10 1992-12-08 Shell Oil Company Method utilizing spot tracer injection and production induced transport for measurement of residual oil saturation
US5193618A (en) 1991-09-12 1993-03-16 Chevron Research And Technology Company Multivalent ion tolerant steam-foaming surfactant composition for use in enhanced oil recovery operations
US5347070A (en) 1991-11-13 1994-09-13 Battelle Pacific Northwest Labs Treating of solid earthen material and a method for measuring moisture content and resistivity of solid earthen material
US5349859A (en) 1991-11-15 1994-09-27 Scientific Engineering Instruments, Inc. Method and apparatus for measuring acoustic wave velocity using impulse response
DE69209466T2 (de) 1991-12-16 1996-08-14 Inst Francais Du Petrol Aktive oder passive Überwachungsanordnung für unterirdische Lagerstätte mittels fester Stationen
CA2058255C (en) 1991-12-20 1997-02-11 Roland P. Leaute Recovery and upgrading of hydrocarbons utilizing in situ combustion and horizontal wells
US5246071A (en) 1992-01-31 1993-09-21 Texaco Inc. Steamflooding with alternating injection and production cycles
US5420402A (en) 1992-02-05 1995-05-30 Iit Research Institute Methods and apparatus to confine earth currents for recovery of subsurface volatiles and semi-volatiles
US5211230A (en) 1992-02-21 1993-05-18 Mobil Oil Corporation Method for enhanced oil recovery through a horizontal production well in a subsurface formation by in-situ combustion
GB9207174D0 (en) 1992-04-01 1992-05-13 Raychem Sa Nv Method of forming an electrical connection
FI92441C (fi) 1992-04-01 1994-11-10 Vaisala Oy Sähköinen impedanssianturi fysikaalisten suureiden, etenkin lämpötilan mittaamiseksi ja menetelmä kyseisen anturin valmistamiseksi
US5255740A (en) 1992-04-13 1993-10-26 Rrkt Company Secondary recovery process
US5332036A (en) 1992-05-15 1994-07-26 The Boc Group, Inc. Method of recovery of natural gases from underground coal formations
US5366012A (en) 1992-06-09 1994-11-22 Shell Oil Company Method of completing an uncased section of a borehole
US5392854A (en) 1992-06-12 1995-02-28 Shell Oil Company Oil recovery process
US5297626A (en) 1992-06-12 1994-03-29 Shell Oil Company Oil recovery process
US5226961A (en) 1992-06-12 1993-07-13 Shell Oil Company High temperature wellbore cement slurry
US5255742A (en) 1992-06-12 1993-10-26 Shell Oil Company Heat injection process
US5236039A (en) 1992-06-17 1993-08-17 General Electric Company Balanced-line RF electrode system for use in RF ground heating to recover oil from oil shale
US5295763A (en) 1992-06-30 1994-03-22 Chambers Development Co., Inc. Method for controlling gas migration from a landfill
JP3276407B2 (ja) * 1992-07-03 2002-04-22 東京瓦斯株式会社 地下の炭化水素水和物の採取法
US5315065A (en) 1992-08-21 1994-05-24 Donovan James P O Versatile electrically insulating waterproof connectors
US5305829A (en) 1992-09-25 1994-04-26 Chevron Research And Technology Company Oil production from diatomite formations by fracture steamdrive
US5229583A (en) 1992-09-28 1993-07-20 Shell Oil Company Surface heating blanket for soil remediation
US5276720A (en) * 1992-11-02 1994-01-04 General Electric Company Emergency cooling system and method
US5339904A (en) 1992-12-10 1994-08-23 Mobil Oil Corporation Oil recovery optimization using a well having both horizontal and vertical sections
US5358045A (en) 1993-02-12 1994-10-25 Chevron Research And Technology Company, A Division Of Chevron U.S.A. Inc. Enhanced oil recovery method employing a high temperature brine tolerant foam-forming composition
CA2096034C (en) 1993-05-07 1996-07-02 Kenneth Edwin Kisman Horizontal well gravity drainage combustion process for oil recovery
US5360067A (en) 1993-05-17 1994-11-01 Meo Iii Dominic Vapor-extraction system for removing hydrocarbons from soil
US5384430A (en) * 1993-05-18 1995-01-24 Baker Hughes Incorporated Double armor cable with auxiliary line
SE503278C2 (sv) 1993-06-07 1996-05-13 Kabeldon Ab Förfarande vid skarvning av två kabelparter, samt skarvkropp och monteringsverktyg för användning vid förfarandet
US5325918A (en) 1993-08-02 1994-07-05 The United States Of America As Represented By The United States Department Of Energy Optimal joule heating of the subsurface
WO1995006093A1 (en) 1993-08-20 1995-03-02 Technological Resources Pty. Ltd. Enhanced hydrocarbon recovery method
US5377556A (en) * 1993-09-27 1995-01-03 Teleflex Incorporated Core element tension mechanism having length adjust
US5358058A (en) * 1993-09-27 1994-10-25 Reedrill, Inc. Drill automation control system
US5377756A (en) 1993-10-28 1995-01-03 Mobil Oil Corporation Method for producing low permeability reservoirs using a single well
US5388641A (en) 1993-11-03 1995-02-14 Amoco Corporation Method for reducing the inert gas fraction in methane-containing gaseous mixtures obtained from underground formations
US5388643A (en) 1993-11-03 1995-02-14 Amoco Corporation Coalbed methane recovery using pressure swing adsorption separation
US5566755A (en) 1993-11-03 1996-10-22 Amoco Corporation Method for recovering methane from a solid carbonaceous subterranean formation
US5388640A (en) * 1993-11-03 1995-02-14 Amoco Corporation Method for producing methane-containing gaseous mixtures
US5388642A (en) 1993-11-03 1995-02-14 Amoco Corporation Coalbed methane recovery using membrane separation of oxygen from air
US5388645A (en) 1993-11-03 1995-02-14 Amoco Corporation Method for producing methane-containing gaseous mixtures
US5589775A (en) 1993-11-22 1996-12-31 Vector Magnetics, Inc. Rotating magnet for distance and direction measurements from a first borehole to a second borehole
US5411086A (en) 1993-12-09 1995-05-02 Mobil Oil Corporation Oil recovery by enhanced imbitition in low permeability reservoirs
US5435666A (en) 1993-12-14 1995-07-25 Environmental Resources Management, Inc. Methods for isolating a water table and for soil remediation
US5411089A (en) 1993-12-20 1995-05-02 Shell Oil Company Heat injection process
US5404952A (en) 1993-12-20 1995-04-11 Shell Oil Company Heat injection process and apparatus
US5433271A (en) 1993-12-20 1995-07-18 Shell Oil Company Heat injection process
US5634984A (en) 1993-12-22 1997-06-03 Union Oil Company Of California Method for cleaning an oil-coated substrate
US5541517A (en) 1994-01-13 1996-07-30 Shell Oil Company Method for drilling a borehole from one cased borehole to another cased borehole
US5453599A (en) 1994-02-14 1995-09-26 Hoskins Manufacturing Company Tubular heating element with insulating core
US5411104A (en) 1994-02-16 1995-05-02 Conoco Inc. Coalbed methane drilling
CA2144597C (en) 1994-03-18 1999-08-10 Paul J. Latimer Improved emat probe and technique for weld inspection
US5415231A (en) 1994-03-21 1995-05-16 Mobil Oil Corporation Method for producing low permeability reservoirs using steam
US5439054A (en) 1994-04-01 1995-08-08 Amoco Corporation Method for treating a mixture of gaseous fluids within a solid carbonaceous subterranean formation
US5553478A (en) 1994-04-08 1996-09-10 Burndy Corporation Hand-held compression tool
US5431224A (en) 1994-04-19 1995-07-11 Mobil Oil Corporation Method of thermal stimulation for recovery of hydrocarbons
US5484020A (en) 1994-04-25 1996-01-16 Shell Oil Company Remedial wellbore sealing with unsaturated monomer system
US5429194A (en) 1994-04-29 1995-07-04 Western Atlas International, Inc. Method for inserting a wireline inside coiled tubing
US5409071A (en) 1994-05-23 1995-04-25 Shell Oil Company Method to cement a wellbore
US5503226A (en) 1994-06-22 1996-04-02 Wadleigh; Eugene E. Process for recovering hydrocarbons by thermally assisted gravity segregation
AU2241695A (en) 1994-07-18 1996-02-16 Babcock & Wilcox Co., The Sensor transport system for flash butt welder
US5632336A (en) 1994-07-28 1997-05-27 Texaco Inc. Method for improving injectivity of fluids in oil reservoirs
US5747750A (en) 1994-08-31 1998-05-05 Exxon Production Research Company Single well system for mapping sources of acoustic energy
US5449047A (en) * 1994-09-07 1995-09-12 Ingersoll-Rand Company Automatic control of drilling system
US5525322A (en) 1994-10-12 1996-06-11 The Regents Of The University Of California Method for simultaneous recovery of hydrogen from water and from hydrocarbons
US5553189A (en) 1994-10-18 1996-09-03 Shell Oil Company Radiant plate heater for treatment of contaminated surfaces
US5624188A (en) 1994-10-20 1997-04-29 West; David A. Acoustic thermometer
US5497087A (en) 1994-10-20 1996-03-05 Shell Oil Company NMR logging of natural gas reservoirs
US5498960A (en) 1994-10-20 1996-03-12 Shell Oil Company NMR logging of natural gas in reservoirs
TNSN95131A1 (fr) 1994-12-21 1996-02-06 Shell Int Research Forage orientable avec moteur de fond
US5554453A (en) 1995-01-04 1996-09-10 Energy Research Corporation Carbonate fuel cell system with thermally integrated gasification
US6088294A (en) 1995-01-12 2000-07-11 Baker Hughes Incorporated Drilling system with an acoustic measurement-while-driving system for determining parameters of interest and controlling the drilling direction
CA2209947C (en) 1995-01-12 1999-06-01 Baker Hughes Incorporated A measurement-while-drilling acoustic system employing multiple, segmented transmitters and receivers
US6065538A (en) 1995-02-09 2000-05-23 Baker Hughes Corporation Method of obtaining improved geophysical information about earth formations
DE19505517A1 (de) 1995-02-10 1996-08-14 Siegfried Schwert Verfahren zum Herausziehen eines im Erdreich verlegten Rohres
US5594211A (en) 1995-02-22 1997-01-14 Burndy Corporation Electrical solder splice connector
CA2152521C (en) 1995-03-01 2000-06-20 Jack E. Bridges Low flux leakage cables and cable terminations for a.c. electrical heating of oil deposits
US5621844A (en) 1995-03-01 1997-04-15 Uentech Corporation Electrical heating of mineral well deposits using downhole impedance transformation networks
US5935421A (en) 1995-05-02 1999-08-10 Exxon Research And Engineering Company Continuous in-situ combination process for upgrading heavy oil
US5569845A (en) 1995-05-16 1996-10-29 Selee Corporation Apparatus and method for detecting molten salt in molten metal
US5911898A (en) 1995-05-25 1999-06-15 Electric Power Research Institute Method and apparatus for providing multiple autoregulated temperatures
US5571403A (en) 1995-06-06 1996-11-05 Texaco Inc. Process for extracting hydrocarbons from diatomite
AU3721295A (en) 1995-06-20 1997-01-22 Elan Energy Insulated and/or concentric coiled tubing
AUPN469395A0 (en) 1995-08-08 1995-08-31 Gearhart United Pty Ltd Borehole drill bit stabiliser
US5669275A (en) 1995-08-18 1997-09-23 Mills; Edward Otis Conductor insulation remover
US5801332A (en) 1995-08-31 1998-09-01 Minnesota Mining And Manufacturing Company Elastically recoverable silicone splice cover
JPH0972738A (ja) * 1995-09-05 1997-03-18 Fujii Kiso Sekkei Jimusho:Kk ボアホール壁面の性状調査方法と装置
US5899958A (en) 1995-09-11 1999-05-04 Halliburton Energy Services, Inc. Logging while drilling borehole imaging and dipmeter device
DE19536378A1 (de) 1995-09-29 1997-04-03 Bayer Ag Heterocyclische Aryl-, Alkyl- und Cycloalkylessigsäureamide
US5700161A (en) 1995-10-13 1997-12-23 Baker Hughes Incorporated Two-piece lead seal pothead connector
US5759022A (en) 1995-10-16 1998-06-02 Gas Research Institute Method and system for reducing NOx and fuel emissions in a furnace
GB9521944D0 (en) 1995-10-26 1996-01-03 Camco Drilling Group Ltd A drilling assembly for use in drilling holes in subsurface formations
RU2102587C1 (ru) * 1995-11-10 1998-01-20 Линецкий Александр Петрович Способ разработки и увеличения степени извлечения нефти, газа и других полезных ископаемых из земных недр
US5738178A (en) 1995-11-17 1998-04-14 Baker Hughes Incorporated Method and apparatus for navigational drilling with a downhole motor employing independent drill string and bottomhole assembly rotary orientation and rotation
US5890840A (en) 1995-12-08 1999-04-06 Carter, Jr.; Ernest E. In situ construction of containment vault under a radioactive or hazardous waste site
US5619611A (en) 1995-12-12 1997-04-08 Tub Tauch-Und Baggertechnik Gmbh Device for removing downhole deposits utilizing tubular housing and passing electric current through fluid heating medium contained therein
GB9526120D0 (en) 1995-12-21 1996-02-21 Raychem Sa Nv Electrical connector
JP3747066B2 (ja) 1995-12-27 2006-02-22 シエル・インターナシヨネイル・リサーチ・マーチヤツピイ・ベー・ウイ 無炎燃焼器
IE960011A1 (en) 1996-01-10 1997-07-16 Padraig Mcalister Structural ice composites, processes for their construction¹and their use as artificial islands and other fixed and¹floating structures
US5751895A (en) 1996-02-13 1998-05-12 Eor International, Inc. Selective excitation of heating electrodes for oil wells
US5784530A (en) 1996-02-13 1998-07-21 Eor International, Inc. Iterated electrodes for oil wells
US5826655A (en) 1996-04-25 1998-10-27 Texaco Inc Method for enhanced recovery of viscous oil deposits
NO302493B1 (no) * 1996-05-13 1998-03-09 Maritime Hydraulics As Glideskjöt
US5652389A (en) 1996-05-22 1997-07-29 The United States Of America As Represented By The Secretary Of Commerce Non-contact method and apparatus for inspection of inertia welds
US6022834A (en) 1996-05-24 2000-02-08 Oil Chem Technologies, Inc. Alkaline surfactant polymer flooding composition and process
US5769569A (en) 1996-06-18 1998-06-23 Southern California Gas Company In-situ thermal desorption of heavy hydrocarbons in vadose zone
US5828797A (en) 1996-06-19 1998-10-27 Meggitt Avionics, Inc. Fiber optic linked flame sensor
EP0909258A1 (en) 1996-06-21 1999-04-21 Syntroleum Corporation Synthesis gas production system and method
US5788376A (en) 1996-07-01 1998-08-04 General Motors Corporation Temperature sensor
PE17599A1 (es) 1996-07-09 1999-02-22 Syntroleum Corp Procedimiento para convertir gases a liquidos
US6806233B2 (en) * 1996-08-02 2004-10-19 M-I Llc Methods of using reversible phase oil based drilling fluid
US5826653A (en) 1996-08-02 1998-10-27 Scientific Applications & Research Associates, Inc. Phased array approach to retrieve gases, liquids, or solids from subaqueous geologic or man-made formations
US6116357A (en) 1996-09-09 2000-09-12 Smith International, Inc. Rock drill bit with back-reaming protection
RU2133335C1 (ru) * 1996-09-11 1999-07-20 Юрий Алексеевич Трутнев Способ разработки нефтяных месторождений и переработки нефти и устройство для его осуществления
SE507262C2 (sv) 1996-10-03 1998-05-04 Per Karlsson Dragavlastning samt verktyg för applicering därav
US5782301A (en) 1996-10-09 1998-07-21 Baker Hughes Incorporated Oil well heater cable
US5875283A (en) 1996-10-11 1999-02-23 Lufran Incorporated Purged grounded immersion heater
US6056057A (en) 1996-10-15 2000-05-02 Shell Oil Company Heater well method and apparatus
US6079499A (en) 1996-10-15 2000-06-27 Shell Oil Company Heater well method and apparatus
US5861137A (en) 1996-10-30 1999-01-19 Edlund; David J. Steam reformer with internal hydrogen purification
US5816325A (en) * 1996-11-27 1998-10-06 Future Energy, Llc Methods and apparatus for enhanced recovery of viscous deposits by thermal stimulation
US7426961B2 (en) 2002-09-03 2008-09-23 Bj Services Company Method of treating subterranean formations with porous particulate materials
US5862858A (en) 1996-12-26 1999-01-26 Shell Oil Company Flameless combustor
US6427124B1 (en) 1997-01-24 2002-07-30 Baker Hughes Incorporated Semblance processing for an acoustic measurement-while-drilling system for imaging of formation boundaries
SE510452C2 (sv) 1997-02-03 1999-05-25 Asea Brown Boveri Transformator med spänningsregleringsorgan
US5821414A (en) * 1997-02-07 1998-10-13 Noy; Koen Survey apparatus and methods for directional wellbore wireline surveying
US6631563B2 (en) * 1997-02-07 2003-10-14 James Brosnahan Survey apparatus and methods for directional wellbore surveying
US6039121A (en) 1997-02-20 2000-03-21 Rangewest Technologies Ltd. Enhanced lift method and apparatus for the production of hydrocarbons
GB9704181D0 (en) 1997-02-28 1997-04-16 Thompson James Apparatus and method for installation of ducts
US5923170A (en) 1997-04-04 1999-07-13 Vector Magnetics, Inc. Method for near field electromagnetic proximity determination for guidance of a borehole drill
US5926437A (en) 1997-04-08 1999-07-20 Halliburton Energy Services, Inc. Method and apparatus for seismic exploration
US5984578A (en) 1997-04-11 1999-11-16 New Jersey Institute Of Technology Apparatus and method for in situ removal of contaminants using sonic energy
US5802870A (en) 1997-05-02 1998-09-08 Uop Llc Sorption cooling process and system
EP1357403A3 (en) 1997-05-02 2004-01-02 Sensor Highway Limited A method of generating electric power in a wellbore
WO1998050179A1 (en) 1997-05-07 1998-11-12 Shell Internationale Research Maatschappij B.V. Remediation method
US6023554A (en) 1997-05-20 2000-02-08 Shell Oil Company Electrical heater
US5927408A (en) 1997-05-22 1999-07-27 Bucyrus International, Inc. Head brake release with memory and method of controlling a drill head
AU720947B2 (en) 1997-06-05 2000-06-15 Shell Internationale Research Maatschappij B.V. Remediation method
US6102122A (en) 1997-06-11 2000-08-15 Shell Oil Company Control of heat injection based on temperature and in-situ stress measurement
US6050348A (en) 1997-06-17 2000-04-18 Canrig Drilling Technology Ltd. Drilling method and apparatus
US6112808A (en) 1997-09-19 2000-09-05 Isted; Robert Edward Method and apparatus for subterranean thermal conditioning
CZ298765B6 (cs) * 1997-06-19 2008-01-23 European Organization For Nuclear Research Způsob exponování materiálu neutronovým tokem, způsob produkování užitečného izotopu zahrnující uvedený způsob exponování a způsob transmutace alespoň jednoho dlouhodobého izotopuzahrnující uvedený způsob exponování
US5984010A (en) * 1997-06-23 1999-11-16 Elias; Ramon Hydrocarbon recovery systems and methods
CA2208767A1 (en) 1997-06-26 1998-12-26 Reginald D. Humphreys Tar sands extraction process
AU3710697A (en) 1997-07-01 1999-01-25 Alexandr Petrovich Linetsky Method for exploiting gas and oil fields and for increasing gas and crude oil output
US5992522A (en) 1997-08-12 1999-11-30 Steelhead Reclamation Ltd. Process and seal for minimizing interzonal migration in boreholes
US6321862B1 (en) 1997-09-08 2001-11-27 Baker Hughes Incorporated Rotary drill bits for directional drilling employing tandem gage pad arrangement with cutting elements and up-drill capability
US5868202A (en) 1997-09-22 1999-02-09 Tarim Associates For Scientific Mineral And Oil Exploration Ag Hydrologic cells for recovery of hydrocarbons or thermal energy from coal, oil-shale, tar-sands and oil-bearing formations
US6149344A (en) 1997-10-04 2000-11-21 Master Corporation Acid gas disposal
US6354373B1 (en) 1997-11-26 2002-03-12 Schlumberger Technology Corporation Expandable tubing for a well bore hole and method of expanding
FR2772137B1 (fr) 1997-12-08 1999-12-31 Inst Francais Du Petrole Methode de surveillance sismique d'une zone souterraine en cours d'exploitation permettant une meilleure identification d'evenements significatifs
EP1060326B1 (en) 1997-12-11 2003-04-02 Alberta Research Council, Inc. Oilfield in situ hydrocarbon upgrading process
US6152987A (en) 1997-12-15 2000-11-28 Worcester Polytechnic Institute Hydrogen gas-extraction module and method of fabrication
US6094048A (en) 1997-12-18 2000-07-25 Shell Oil Company NMR logging of natural gas reservoirs
NO305720B1 (no) 1997-12-22 1999-07-12 Eureka Oil Asa FremgangsmÕte for Õ °ke oljeproduksjonen fra et oljereservoar
US6026914A (en) 1998-01-28 2000-02-22 Alberta Oil Sands Technology And Research Authority Wellbore profiling system
US6540018B1 (en) 1998-03-06 2003-04-01 Shell Oil Company Method and apparatus for heating a wellbore
MA24902A1 (fr) 1998-03-06 2000-04-01 Shell Int Research Rechauffeur electrique
US6269876B1 (en) 1998-03-06 2001-08-07 Shell Oil Company Electrical heater
US6247542B1 (en) 1998-03-06 2001-06-19 Baker Hughes Incorporated Non-rotating sensor assembly for measurement-while-drilling applications
US6035701A (en) 1998-04-15 2000-03-14 Lowry; William E. Method and system to locate leaks in subsurface containment structures using tracer gases
AU3978399A (en) 1998-05-12 1999-11-29 Lockheed Martin Corporation System and process for secondary hydrocarbon recovery
US6016867A (en) 1998-06-24 2000-01-25 World Energy Systems, Incorporated Upgrading and recovery of heavy crude oils and natural bitumens by in situ hydrovisbreaking
US6016868A (en) 1998-06-24 2000-01-25 World Energy Systems, Incorporated Production of synthetic crude oil from heavy hydrocarbons recovered by in situ hydrovisbreaking
US5958365A (en) 1998-06-25 1999-09-28 Atlantic Richfield Company Method of producing hydrogen from heavy crude oil using solvent deasphalting and partial oxidation methods
NO984235L (no) 1998-09-14 2000-03-15 Cit Alcatel Oppvarmingssystem for metallrør for rõoljetransport
US6388947B1 (en) 1998-09-14 2002-05-14 Tomoseis, Inc. Multi-crosswell profile 3D imaging and method
DE69930290T2 (de) 1998-09-25 2006-12-14 Tesco Corp., Calgary System, vorrichtung und verfahren zur installierung von steuerleitungen in einer erdbohrung
US6591916B1 (en) * 1998-10-14 2003-07-15 Coupler Developments Limited Drilling method
US6192748B1 (en) 1998-10-30 2001-02-27 Computalog Limited Dynamic orienting reference system for directional drilling
US6138753A (en) 1998-10-30 2000-10-31 Mohaupt Family Trust Technique for treating hydrocarbon wells
US5968349A (en) 1998-11-16 1999-10-19 Bhp Minerals International Inc. Extraction of bitumen from bitumen froth and biotreatment of bitumen froth tailings generated from tar sands
US20040035582A1 (en) 2002-08-22 2004-02-26 Zupanick Joseph A. System and method for subterranean access
US6280000B1 (en) 1998-11-20 2001-08-28 Joseph A. Zupanick Method for production of gas from a coal seam using intersecting well bores
CN1306145C (zh) 1998-12-22 2007-03-21 切夫里昂奥罗尼特有限责任公司 从含烃的地下岩层中采收原油的方法和强化采油的表面活性剂
CN2357124Y (zh) * 1999-01-15 2000-01-05 辽河石油勘探局曙光采油厂 可伸缩热采封隔器
US6078868A (en) 1999-01-21 2000-06-20 Baker Hughes Incorporated Reference signal encoding for seismic while drilling measurement
US6318469B1 (en) 1999-02-09 2001-11-20 Schlumberger Technology Corp. Completion equipment having a plurality of fluid paths for use in a well
US6739409B2 (en) 1999-02-09 2004-05-25 Baker Hughes Incorporated Method and apparatus for a downhole NMR MWD tool configuration
US6429784B1 (en) 1999-02-19 2002-08-06 Dresser Industries, Inc. Casing mounted sensors, actuators and generators
US6283230B1 (en) 1999-03-01 2001-09-04 Jasper N. Peters Method and apparatus for lateral well drilling utilizing a rotating nozzle
US7591304B2 (en) * 1999-03-05 2009-09-22 Varco I/P, Inc. Pipe running tool having wireless telemetry
US6155117A (en) 1999-03-18 2000-12-05 Mcdermott Technology, Inc. Edge detection and seam tracking with EMATs
US6561269B1 (en) 1999-04-30 2003-05-13 The Regents Of The University Of California Canister, sealing method and composition for sealing a borehole
US6110358A (en) 1999-05-21 2000-08-29 Exxon Research And Engineering Company Process for manufacturing improved process oils using extraction of hydrotreated distillates
EG22117A (en) * 1999-06-03 2002-08-30 Exxonmobil Upstream Res Co Method and apparatus for controlling pressure and detecting well control problems during drilling of an offshore well using a gas-lifted riser
US6519308B1 (en) * 1999-06-11 2003-02-11 General Electric Company Corrosion mitigation system for liquid metal nuclear reactors with passive decay heat removal systems
US6257334B1 (en) 1999-07-22 2001-07-10 Alberta Oil Sands Technology And Research Authority Steam-assisted gravity drainage heavy oil recovery process
US6269310B1 (en) 1999-08-25 2001-07-31 Tomoseis Corporation System for eliminating headwaves in a tomographic process
US6446737B1 (en) 1999-09-14 2002-09-10 Deep Vision Llc Apparatus and method for rotating a portion of a drill string
US6193010B1 (en) 1999-10-06 2001-02-27 Tomoseis Corporation System for generating a seismic signal in a borehole
US6196350B1 (en) 1999-10-06 2001-03-06 Tomoseis Corporation Apparatus and method for attenuating tube waves in a borehole
DE19948819C2 (de) 1999-10-09 2002-01-24 Airbus Gmbh Heizleiter mit einem Anschlußelement und/oder einem Abschlußelement sowie ein Verfahren zur Herstellung desselben
US6288372B1 (en) 1999-11-03 2001-09-11 Tyco Electronics Corporation Electric cable having braidless polymeric ground plane providing fault detection
US6353706B1 (en) 1999-11-18 2002-03-05 Uentech International Corporation Optimum oil-well casing heating
US6422318B1 (en) 1999-12-17 2002-07-23 Scioto County Regional Water District #1 Horizontal well system
US6452105B2 (en) 2000-01-12 2002-09-17 Meggitt Safety Systems, Inc. Coaxial cable assembly with a discontinuous outer jacket
US6427783B2 (en) 2000-01-12 2002-08-06 Baker Hughes Incorporated Steerable modular drilling assembly
US7259688B2 (en) 2000-01-24 2007-08-21 Shell Oil Company Wireless reservoir production control
US6679332B2 (en) 2000-01-24 2004-01-20 Shell Oil Company Petroleum well having downhole sensors, communication and power
US6633236B2 (en) 2000-01-24 2003-10-14 Shell Oil Company Permanent downhole, wireless, two-way telemetry backbone using redundant repeaters
US6715550B2 (en) 2000-01-24 2004-04-06 Shell Oil Company Controllable gas-lift well and valve
MY128294A (en) 2000-03-02 2007-01-31 Shell Int Research Use of downhole high pressure gas in a gas-lift well
US7170424B2 (en) 2000-03-02 2007-01-30 Shell Oil Company Oil well casting electrical power pick-off points
SE0000688L (sv) 2000-03-02 2001-05-21 Sandvik Ab Bergborrkrona samt förfarande för dess tillverkning
OA12225A (en) 2000-03-02 2006-05-10 Shell Int Research Controlled downhole chemical injection.
US6357526B1 (en) 2000-03-16 2002-03-19 Kellogg Brown & Root, Inc. Field upgrading of heavy oil and bitumen
US6485232B1 (en) 2000-04-14 2002-11-26 Board Of Regents, The University Of Texas System Low cost, self regulating heater for use in an in situ thermal desorption soil remediation system
US6918444B2 (en) 2000-04-19 2005-07-19 Exxonmobil Upstream Research Company Method for production of hydrocarbons from organic-rich rock
GB0009662D0 (en) 2000-04-20 2000-06-07 Scotoil Group Plc Gas and oil production
US7011154B2 (en) 2000-04-24 2006-03-14 Shell Oil Company In situ recovery from a kerogen and liquid hydrocarbon containing formation
US20030085034A1 (en) 2000-04-24 2003-05-08 Wellington Scott Lee In situ thermal processing of a coal formation to produce pyrolsis products
US6698515B2 (en) 2000-04-24 2004-03-02 Shell Oil Company In situ thermal processing of a coal formation using a relatively slow heating rate
US20030066642A1 (en) 2000-04-24 2003-04-10 Wellington Scott Lee In situ thermal processing of a coal formation producing a mixture with oxygenated hydrocarbons
US6715546B2 (en) 2000-04-24 2004-04-06 Shell Oil Company In situ production of synthesis gas from a hydrocarbon containing formation through a heat source wellbore
US7096953B2 (en) 2000-04-24 2006-08-29 Shell Oil Company In situ thermal processing of a coal formation using a movable heating element
US6588504B2 (en) 2000-04-24 2003-07-08 Shell Oil Company In situ thermal processing of a coal formation to produce nitrogen and/or sulfur containing formation fluids
US6742593B2 (en) 2000-04-24 2004-06-01 Shell Oil Company In situ thermal processing of a hydrocarbon containing formation using heat transfer from a heat transfer fluid to heat the formation
US6715548B2 (en) 2000-04-24 2004-04-06 Shell Oil Company In situ thermal processing of a hydrocarbon containing formation to produce nitrogen containing formation fluids
US6584406B1 (en) 2000-06-15 2003-06-24 Geo-X Systems, Ltd. Downhole process control method utilizing seismic communication
WO2002057805A2 (en) 2000-06-29 2002-07-25 Tubel Paulo S Method and system for monitoring smart structures utilizing distributed optical sensors
US6585046B2 (en) 2000-08-28 2003-07-01 Baker Hughes Incorporated Live well heater cable
US6412559B1 (en) 2000-11-24 2002-07-02 Alberta Research Council Inc. Process for recovering methane and/or sequestering fluids
FR2817172B1 (fr) * 2000-11-29 2003-09-26 Inst Francais Du Petrole Reacteur de conversion chimique d'une charge avec apports de chaleur et circulation croisee de la charge et d'un catalyseur
US20020110476A1 (en) 2000-12-14 2002-08-15 Maziasz Philip J. Heat and corrosion resistant cast stainless steels with improved high temperature strength and ductility
US20020112987A1 (en) 2000-12-15 2002-08-22 Zhiguo Hou Slurry hydroprocessing for heavy oil upgrading using supported slurry catalysts
US6554075B2 (en) * 2000-12-15 2003-04-29 Halliburton Energy Services, Inc. CT drilling rig
US20020112890A1 (en) 2001-01-22 2002-08-22 Wentworth Steven W. Conduit pulling apparatus and method for use in horizontal drilling
US6516891B1 (en) 2001-02-08 2003-02-11 L. Murray Dallas Dual string coil tubing injector assembly
US20020153141A1 (en) 2001-04-19 2002-10-24 Hartman Michael G. Method for pumping fluids
US7004247B2 (en) 2001-04-24 2006-02-28 Shell Oil Company Conductor-in-conduit heat sources for in situ thermal processing of an oil shale formation
CN100545415C (zh) 2001-04-24 2009-09-30 国际壳牌研究有限公司 现场处理含烃地层的方法
US6571888B2 (en) 2001-05-14 2003-06-03 Precision Drilling Technology Services Group, Inc. Apparatus and method for directional drilling with coiled tubing
AU2002345858A1 (en) 2001-07-03 2003-01-29 Cci Thermal Technologies, Inc. Corrugated metal ribbon heating element
RU2223397C2 (ru) * 2001-07-19 2004-02-10 Хайрединов Нил Шахиджанович Способ разработки нефтяного месторождения
US20030029617A1 (en) 2001-08-09 2003-02-13 Anadarko Petroleum Company Apparatus, method and system for single well solution-mining
US6591908B2 (en) * 2001-08-22 2003-07-15 Alberta Science And Research Authority Hydrocarbon production process with decreasing steam and/or water/solvent ratio
US6695062B2 (en) * 2001-08-27 2004-02-24 Baker Hughes Incorporated Heater cable and method for manufacturing
MY129091A (en) 2001-09-07 2007-03-30 Exxonmobil Upstream Res Co Acid gas disposal method
US6755251B2 (en) 2001-09-07 2004-06-29 Exxonmobil Upstream Research Company Downhole gas separation method and system
US6470977B1 (en) 2001-09-18 2002-10-29 Halliburton Energy Services, Inc. Steerable underreaming bottom hole assembly and method
US6886638B2 (en) 2001-10-03 2005-05-03 Schlumbergr Technology Corporation Field weldable connections
US6969123B2 (en) 2001-10-24 2005-11-29 Shell Oil Company Upgrading and mining of coal
US7104319B2 (en) 2001-10-24 2006-09-12 Shell Oil Company In situ thermal processing of a heavy oil diatomite formation
US7165615B2 (en) 2001-10-24 2007-01-23 Shell Oil Company In situ recovery from a hydrocarbon containing formation using conductor-in-conduit heat sources with an electrically conductive material in the overburden
NZ532091A (en) 2001-10-24 2005-12-23 Shell Int Research In situ recovery from a hydrocarbon containing formation using barriers
RU2310890C2 (ru) * 2001-10-24 2007-11-20 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Формирование отверстий в содержащем углеводороды пласте с использованием магнитного слежения
US7077199B2 (en) 2001-10-24 2006-07-18 Shell Oil Company In situ thermal processing of an oil reservoir formation
US7090013B2 (en) 2001-10-24 2006-08-15 Shell Oil Company In situ thermal processing of a hydrocarbon containing formation to produce heated fluids
ATE402294T1 (de) 2001-10-24 2008-08-15 Shell Int Research Vereisung von böden als vorwegmassnahme zu deren thermischer behandlung
US6736222B2 (en) 2001-11-05 2004-05-18 Vector Magnetics, Llc Relative drill bit direction measurement
US6684948B1 (en) 2002-01-15 2004-02-03 Marshall T. Savage Apparatus and method for heating subterranean formations using fuel cells
US6679326B2 (en) 2002-01-15 2004-01-20 Bohdan Zakiewicz Pro-ecological mining system
US7032809B1 (en) 2002-01-18 2006-04-25 Steel Ventures, L.L.C. Seam-welded metal pipe and method of making the same without seam anneal
US6854534B2 (en) 2002-01-22 2005-02-15 James I. Livingstone Two string drilling system using coil tubing
US6958195B2 (en) 2002-02-19 2005-10-25 Utc Fuel Cells, Llc Steam generator for a PEM fuel cell power plant
US7513318B2 (en) 2002-02-19 2009-04-07 Smith International, Inc. Steerable underreamer/stabilizer assembly and method
US6715553B2 (en) * 2002-05-31 2004-04-06 Halliburton Energy Services, Inc. Methods of generating gas in well fluids
US6942037B1 (en) 2002-08-15 2005-09-13 Clariant Finance (Bvi) Limited Process for mitigation of wellbore contaminants
WO2004018828A1 (en) 2002-08-21 2004-03-04 Presssol Ltd. Reverse circulation directional and horizontal drilling using concentric coil tubing
US20080069289A1 (en) * 2002-09-16 2008-03-20 Peterson Otis G Self-regulating nuclear power module
JP2004111620A (ja) 2002-09-18 2004-04-08 Murata Mfg Co Ltd イグナイタトランス
CN1717529B (zh) * 2002-10-24 2010-05-26 国际壳牌研究有限公司 用于加热地下或者地下井孔的方法和系统
WO2004038175A1 (en) 2002-10-24 2004-05-06 Shell Internationale Research Maatschappij B.V. Inhibiting wellbore deformation during in situ thermal processing of a hydrocarbon containing formation
WO2004042188A2 (en) 2002-11-06 2004-05-21 Canitron Systems, Inc. Down hole induction heating tool and method of operating and manufacturing same
US20040111212A1 (en) 2002-11-22 2004-06-10 Broeck Wim Van Den Method for determining a track of a geographical trajectory
US7048051B2 (en) 2003-02-03 2006-05-23 Gen Syn Fuels Recovery of products from oil shale
US7055602B2 (en) 2003-03-11 2006-06-06 Shell Oil Company Method and composition for enhanced hydrocarbons recovery
FR2853904B1 (fr) 2003-04-15 2007-11-16 Air Liquide Procede de production de liquides hydrocarbones mettant en oeuvre un procede fischer-tropsch
US7121342B2 (en) 2003-04-24 2006-10-17 Shell Oil Company Thermal processes for subsurface formations
US6951250B2 (en) 2003-05-13 2005-10-04 Halliburton Energy Services, Inc. Sealant compositions and methods of using the same to isolate a subterranean zone from a disposal well
RU2349745C2 (ru) 2003-06-24 2009-03-20 Эксонмобил Апстрим Рисерч Компани Способ обработки подземного пласта для конверсии органического вещества в извлекаемые углеводороды (варианты)
US6881897B2 (en) 2003-07-10 2005-04-19 Yazaki Corporation Shielding structure of shielding electric wire
US7073577B2 (en) 2003-08-29 2006-07-11 Applied Geotech, Inc. Array of wells with connected permeable zones for hydrocarbon recovery
US7114880B2 (en) 2003-09-26 2006-10-03 Carter Jr Ernest E Process for the excavation of buried waste
US7147057B2 (en) 2003-10-06 2006-12-12 Halliburton Energy Services, Inc. Loop systems and methods of using the same for conveying and distributing thermal energy into a wellbore
EA010677B1 (ru) 2003-11-03 2008-10-30 Эксонмобил Апстрим Рисерч Компани Способ извлечения углеводородов из непроницаемых нефтеносных сланцев
US6978837B2 (en) * 2003-11-13 2005-12-27 Yemington Charles R Production of natural gas from hydrates
JP3914994B2 (ja) * 2004-01-28 2007-05-16 独立行政法人産業技術総合研究所 メタンハイドレート堆積層からの天然ガス生産設備と発電設備を具備する統合設備
GB2412389A (en) * 2004-03-27 2005-09-28 Cleansorb Ltd Process for treating underground formations
CA2579496A1 (en) 2004-04-23 2005-11-03 Shell Internationale Research Maatschappij B.V. Subsurface electrical heaters using nitride insulation
ATE556468T1 (de) 2004-09-03 2012-05-15 Watlow Electric Mfg Leistungssteuerungssystem
US7398823B2 (en) 2005-01-10 2008-07-15 Conocophillips Company Selective electromagnetic production tool
EA011905B1 (ru) 2005-04-22 2009-06-30 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Способ конверсии in situ с использованием нагревающей системы с замкнутым контуром
AU2006239988B2 (en) 2005-04-22 2010-07-01 Shell Internationale Research Maatschappij B.V. Reduction of heat loads applied to frozen barriers and freeze wells in subsurface formations
US7600585B2 (en) 2005-05-19 2009-10-13 Schlumberger Technology Corporation Coiled tubing drilling rig
US20070044957A1 (en) 2005-05-27 2007-03-01 Oil Sands Underground Mining, Inc. Method for underground recovery of hydrocarbons
US7849934B2 (en) 2005-06-07 2010-12-14 Baker Hughes Incorporated Method and apparatus for collecting drill bit performance data
US7441597B2 (en) 2005-06-20 2008-10-28 Ksn Energies, Llc Method and apparatus for in-situ radiofrequency assisted gravity drainage of oil (RAGD)
WO2007040406A1 (en) 2005-10-03 2007-04-12 Wirescan As System and method for monitoring of electrical cables
US7303007B2 (en) 2005-10-07 2007-12-04 Weatherford Canada Partnership Method and apparatus for transmitting sensor response data and power through a mud motor
AU2006306471B2 (en) 2005-10-24 2010-11-25 Shell Internationale Research Maatschapij B.V. Cogeneration systems and processes for treating hydrocarbon containing formations
RU2303198C1 (ru) * 2006-01-10 2007-07-20 Государственное образовательное учреждение высшего профессионального образования Самарский государственный технический университет Котельная установка
US7647967B2 (en) 2006-01-12 2010-01-19 Jimni Development LLC Drilling and opening reservoir using an oriented fissure to enhance hydrocarbon flow and method of making
US7743826B2 (en) 2006-01-20 2010-06-29 American Shale Oil, Llc In situ method and system for extraction of oil from shale
JP4298709B2 (ja) 2006-01-26 2009-07-22 矢崎総業株式会社 シールド電線の端末処理方法および端末処理装置
US7445041B2 (en) * 2006-02-06 2008-11-04 Shale And Sands Oil Recovery Llc Method and system for extraction of hydrocarbons from oil shale
EP1984599B1 (en) 2006-02-16 2012-03-21 Chevron U.S.A., Inc. Kerogen extraction from subterranean oil shale resources
AU2007240367B2 (en) 2006-04-21 2011-04-07 Shell Internationale Research Maatschappij B.V. High strength alloys
WO2007126676A2 (en) 2006-04-21 2007-11-08 Exxonmobil Upstream Research Company In situ co-development of oil shale with mineral recovery
CA2649850A1 (en) 2006-04-21 2007-11-01 Osum Oil Sands Corp. Method of drilling from a shaft for underground recovery of hydrocarbons
US7461705B2 (en) * 2006-05-05 2008-12-09 Varco I/P, Inc. Directional drilling control
CN101131886A (zh) * 2006-08-21 2008-02-27 吕应中 固有安全、防核扩散、和成本低廉的核能生产方法与装置
US7705607B2 (en) 2006-08-25 2010-04-27 Instrument Manufacturing Company Diagnostic methods for electrical cables utilizing axial tomography
ITMI20061648A1 (it) 2006-08-29 2008-02-29 Star Progetti Tecnologie Applicate Spa Dispositivo di irraggiamento di calore tramite infrarossi
US8528636B2 (en) 2006-09-13 2013-09-10 Baker Hughes Incorporated Instantaneous measurement of drillstring orientation
US8387688B2 (en) 2006-09-14 2013-03-05 Ernest E. Carter, Jr. Method of forming subterranean barriers with molten wax
GB0618108D0 (en) * 2006-09-14 2006-10-25 Technip France Sa Subsea umbilical
US7622677B2 (en) 2006-09-26 2009-11-24 Accutru International Corporation Mineral insulated metal sheathed cable connector and method of forming the connector
US20080078552A1 (en) 2006-09-29 2008-04-03 Osum Oil Sands Corp. Method of heating hydrocarbons
US7665524B2 (en) 2006-09-29 2010-02-23 Ut-Battelle, Llc Liquid metal heat exchanger for efficient heating of soils and geologic formations
BRPI0719868A2 (pt) * 2006-10-13 2014-06-10 Exxonmobil Upstream Res Co Métodos para abaixar a temperatura de uma formação subsuperficial, e para formar uma parede congelada em uma formação subsuperficial
CN101595273B (zh) 2006-10-13 2013-01-02 埃克森美孚上游研究公司 用于原位页岩油开发的优化的井布置
BRPI0719858A2 (pt) 2006-10-13 2015-05-26 Exxonmobil Upstream Res Co Fluido de hidrocarbonetos, e, método para produzir fluidos de hidrocarbonetos.
JP5330999B2 (ja) 2006-10-20 2013-10-30 シエル・インターナシヨネイル・リサーチ・マーチヤツピイ・ベー・ウイ 流体によるタールサンド地層の複数部分中での炭化水素の移動
US7823655B2 (en) 2007-09-21 2010-11-02 Canrig Drilling Technology Ltd. Directional drilling control
US7730936B2 (en) 2007-02-07 2010-06-08 Schlumberger Technology Corporation Active cable for wellbore heating and distributed temperature sensing
DE102007040606B3 (de) 2007-08-27 2009-02-26 Siemens Ag Verfahren und Vorrichtung zur in situ-Förderung von Bitumen oder Schwerstöl
RU2339809C1 (ru) * 2007-03-12 2008-11-27 Открытое акционерное общество "Татнефть" им. В.Д. Шашина Способ сооружения и эксплуатации паронагнетательной скважины
BRPI0808367A2 (pt) 2007-03-22 2014-07-08 Exxonmobil Upstream Res Co Métodos para aquecer uma formação de subsuperfície usando aquecimento por resistência elétrica e para produzir fluidos de hidrocarboneto.
WO2008123352A1 (ja) 2007-03-28 2008-10-16 Nec Corporation 半導体装置
WO2008131171A1 (en) 2007-04-20 2008-10-30 Shell Oil Company Parallel heater system for subsurface formations
US7788967B2 (en) 2007-05-02 2010-09-07 Praxair Technology, Inc. Method and apparatus for leak detection
AU2008253749B2 (en) 2007-05-15 2014-03-20 Exxonmobil Upstream Research Company Downhole burner wells for in situ conversion of organic-rich rock formations
CA2687387C (en) 2007-05-31 2012-08-28 Ernest. E. Carter, Jr. Method for construction of subterranean barriers
CN201106404Y (zh) * 2007-10-10 2008-08-27 中国石油天然气集团公司 套管钻井专用随钻扩眼器
CA2700732A1 (en) 2007-10-19 2009-04-23 Shell Internationale Research Maatschappij B.V. Cryogenic treatment of gas
CA2705198A1 (en) 2007-11-19 2009-05-28 Shell Internationale Research Maatschappij B.V. Systems and methods for producing oil and/or gas
WO2009073727A1 (en) 2007-12-03 2009-06-11 Osum Oil Sands Corp. Method of recovering bitumen from a tunnel or shaft with heating elements and recovery wells
EA022380B1 (ru) 2008-02-07 2015-12-30 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Способ и композиция для улучшенного извлечения углеводородов
WO2009100301A1 (en) 2008-02-07 2009-08-13 Shell Oil Company Method and composition for enhanced hydrocarbons recovery
US7888933B2 (en) 2008-02-15 2011-02-15 Schlumberger Technology Corporation Method for estimating formation hydrocarbon saturation using nuclear magnetic resonance measurements
CA2716233A1 (en) 2008-02-19 2009-08-27 Baker Hughes Incorporated Downhole measurement while drilling system and method
US8151907B2 (en) 2008-04-18 2012-04-10 Shell Oil Company Dual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations
US8277642B2 (en) 2008-06-02 2012-10-02 Korea Technology Industries, Co., Ltd. System for separating bitumen from oil sands
WO2010045097A1 (en) 2008-10-13 2010-04-22 Shell Oil Company Circulated heated transfer fluid heating of subsurface hydrocarbon formations
US7909093B2 (en) 2009-01-15 2011-03-22 Conocophillips Company In situ combustion as adjacent formation heat source
US8812069B2 (en) 2009-01-29 2014-08-19 Hyper Tech Research, Inc Low loss joint for superconducting wire
US20120018421A1 (en) 2009-04-02 2012-01-26 Tyco Thermal Controls Llc Mineral insulated skin effect heating cable
US20100258291A1 (en) 2009-04-10 2010-10-14 Everett De St Remey Edward Heated liners for treating subsurface hydrocarbon containing formations
CA2760967C (en) 2009-05-15 2017-08-29 American Shale Oil, Llc In situ method and system for extraction of oil from shale
US8356935B2 (en) 2009-10-09 2013-01-22 Shell Oil Company Methods for assessing a temperature in a subsurface formation
US8816203B2 (en) 2009-10-09 2014-08-26 Shell Oil Company Compacted coupling joint for coupling insulated conductors
US8502120B2 (en) 2010-04-09 2013-08-06 Shell Oil Company Insulating blocks and methods for installation in insulated conductor heaters
US8875788B2 (en) 2010-04-09 2014-11-04 Shell Oil Company Low temperature inductive heating of subsurface formations
US8739874B2 (en) 2010-04-09 2014-06-03 Shell Oil Company Methods for heating with slots in hydrocarbon formations
US8939207B2 (en) 2010-04-09 2015-01-27 Shell Oil Company Insulated conductor heaters with semiconductor layers
US9127523B2 (en) 2010-04-09 2015-09-08 Shell Oil Company Barrier methods for use in subsurface hydrocarbon formations
US8631866B2 (en) 2010-04-09 2014-01-21 Shell Oil Company Leak detection in circulated fluid systems for heating subsurface formations
WO2012048196A1 (en) 2010-10-08 2012-04-12 Shell Oil Company Methods of heating a subsurface formation using electrically conductive particles
RU2587459C2 (ru) 2011-04-08 2016-06-20 Шелл Интернэшнл Рисерч Маатсхаппий Б.В. Системы для соединения изолированных проводников
US20130087551A1 (en) 2011-10-07 2013-04-11 Shell Oil Company Insulated conductors with dielectric screens
CN104011327B (zh) 2011-10-07 2016-12-14 国际壳牌研究有限公司 利用地下地层中的绝缘导线的介电性能来确定绝缘导线的性能

Patent Citations (99)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US2734579A (en) * 1956-02-14 Production from bituminous sands
US94813A (en) * 1869-09-14 Improvement in torpedoes for oil-wells
US326439A (en) * 1885-09-15 Protecting wells
US48994A (en) * 1865-07-25 Improvement in devices for oil-wells
US2732195A (en) * 1956-01-24 Ljungstrom
US760304A (en) * 1903-10-24 1904-05-17 Frank S Gilbert Heater for oil-wells.
US1342741A (en) * 1918-01-17 1920-06-08 David T Day Process for extracting oils and hydrocarbon material from shale and similar bituminous rocks
US1510655A (en) * 1922-11-21 1924-10-07 Clark Cornelius Process of subterranean distillation of volatile mineral substances
US1634236A (en) * 1925-03-10 1927-06-28 Standard Dev Co Method of and apparatus for recovering oil
US1666488A (en) * 1927-02-05 1928-04-17 Crawshaw Richard Apparatus for extracting oil from shale
US1681523A (en) * 1927-03-26 1928-08-21 Patrick V Downey Apparatus for heating oil wells
US1913395A (en) * 1929-11-14 1933-06-13 Lewis C Karrick Underground gasification of carbonaceous material-bearing substances
US2244256A (en) * 1939-12-16 1941-06-03 Electrical Treating Company Apparatus for clearing wells
US2365591A (en) * 1942-08-15 1944-12-19 Ranney Leo Method for producing oil from viscous deposits
US2423674A (en) * 1942-08-24 1947-07-08 Johnson & Co A Process of catalytic cracking of petroleum hydrocarbons
US2484063A (en) * 1944-08-19 1949-10-11 Thermactor Corp Electric heater for subsurface materials
US2472445A (en) * 1945-02-02 1949-06-07 Thermactor Company Apparatus for treating oil and gas bearing strata
US2444755A (en) * 1946-01-04 1948-07-06 Ralph M Steffen Apparatus for oil sand heating
US2634961A (en) * 1946-01-07 1953-04-14 Svensk Skifferolje Aktiebolage Method of electrothermal production of shale oil
US2466945A (en) * 1946-02-21 1949-04-12 In Situ Gases Inc Generation of synthesis gas
US2497868A (en) * 1946-10-10 1950-02-21 Dalin David Underground exploitation of fuel deposits
US2939689A (en) * 1947-06-24 1960-06-07 Svenska Skifferolje Ab Electrical heater for treating oilshale and the like
US2786660A (en) * 1948-01-05 1957-03-26 Phillips Petroleum Co Apparatus for gasifying coal
US2548360A (en) * 1948-03-29 1951-04-10 Stanley A Germain Electric oil well heater
US2685930A (en) * 1948-08-12 1954-08-10 Union Oil Co Oil well production process
US2630307A (en) * 1948-12-09 1953-03-03 Carbonic Products Inc Method of recovering oil from oil shale
US2595979A (en) * 1949-01-25 1952-05-06 Texas Co Underground liquefaction of coal
US2642943A (en) * 1949-05-20 1953-06-23 Sinclair Oil & Gas Co Oil recovery process
US2593477A (en) * 1949-06-10 1952-04-22 Us Interior Process of underground gasification of coal
US2670802A (en) * 1949-12-16 1954-03-02 Thermactor Company Reviving or increasing the production of clogged or congested oil wells
US2714930A (en) * 1950-12-08 1955-08-09 Union Oil Co Apparatus for preventing paraffin deposition
US2695163A (en) * 1950-12-09 1954-11-23 Stanolind Oil & Gas Co Method for gasification of subterranean carbonaceous deposits
US2630306A (en) * 1952-01-03 1953-03-03 Socony Vacuum Oil Co Inc Subterranean retorting of shales
US2777679A (en) * 1952-03-07 1957-01-15 Svenska Skifferolje Ab Recovering sub-surface bituminous deposits by creating a frozen barrier and heating in situ
US2780450A (en) * 1952-03-07 1957-02-05 Svenska Skifferolje Ab Method of recovering oil and gases from non-consolidated bituminous geological formations by a heating treatment in situ
US2789805A (en) * 1952-05-27 1957-04-23 Svenska Skifferolje Ab Device for recovering fuel from subterraneous fuel-carrying deposits by heating in their natural location using a chain heat transfer member
US2780449A (en) * 1952-12-26 1957-02-05 Sinclair Oil & Gas Co Thermal process for in-situ decomposition of oil shale
US2771954A (en) * 1953-04-29 1956-11-27 Exxon Research Engineering Co Treatment of petroleum production wells
US2703621A (en) * 1953-05-04 1955-03-08 George W Ford Oil well bottom hole flow increasing unit
US2914309A (en) * 1953-05-25 1959-11-24 Svenska Skifferolje Ab Oil and gas recovery from tar sands
US2902270A (en) * 1953-07-17 1959-09-01 Svenska Skifferolje Ab Method of and means in heating of subsurface fuel-containing deposits "in situ"
US2890754A (en) * 1953-10-30 1959-06-16 Svenska Skifferolje Ab Apparatus for recovering combustible substances from subterraneous deposits in situ
US2890755A (en) * 1953-12-19 1959-06-16 Svenska Skifferolje Ab Apparatus for recovering combustible substances from subterraneous deposits in situ
US2841375A (en) * 1954-03-03 1958-07-01 Svenska Skifferolje Ab Method for in-situ utilization of fuels by combustion
US2793696A (en) * 1954-07-22 1957-05-28 Pan American Petroleum Corp Oil recovery by underground combustion
US2923535A (en) * 1955-02-11 1960-02-02 Svenska Skifferolje Ab Situ recovery from carbonaceous deposits
US2862558A (en) * 1955-12-28 1958-12-02 Phillips Petroleum Co Recovering oils from formations
US2906340A (en) * 1956-04-05 1959-09-29 Texaco Inc Method of treating a petroleum producing formation
US3120264A (en) * 1956-07-09 1964-02-04 Texaco Development Corp Recovery of oil by in situ combustion
US2932352A (en) * 1956-10-25 1960-04-12 Union Oil Co Liquid filled well heater
US2804149A (en) * 1956-12-12 1957-08-27 John R Donaldson Oil well heater and reviver
US3127936A (en) * 1957-07-26 1964-04-07 Svenska Skifferolje Ab Method of in situ heating of subsurface preferably fuel containing deposits
US2906337A (en) * 1957-08-16 1959-09-29 Pure Oil Co Method of recovering bitumen
US3007521A (en) * 1957-10-28 1961-11-07 Phillips Petroleum Co Recovery of oil by in situ combustion
US3010516A (en) * 1957-11-18 1961-11-28 Phillips Petroleum Co Burner and process for in situ combustion
US2954826A (en) * 1957-12-02 1960-10-04 William E Sievers Heated well production string
US2994376A (en) * 1957-12-27 1961-08-01 Phillips Petroleum Co In situ combustion process
US3061009A (en) * 1958-01-17 1962-10-30 Svenska Skifferolje Ab Method of recovery from fossil fuel bearing strata
US3062282A (en) * 1958-01-24 1962-11-06 Phillips Petroleum Co Initiation of in situ combustion in a carbonaceous stratum
US3004603A (en) * 1958-03-07 1961-10-17 Phillips Petroleum Co Heater
US3010513A (en) * 1958-06-12 1961-11-28 Phillips Petroleum Co Initiation of in situ combustion in carbonaceous stratum
US2958519A (en) * 1958-06-23 1960-11-01 Phillips Petroleum Co In situ combustion process
US3044545A (en) * 1958-10-02 1962-07-17 Phillips Petroleum Co In situ combustion process
US2950240A (en) * 1958-10-10 1960-08-23 Socony Mobil Oil Co Inc Selective cracking of aliphatic hydrocarbons
US2974937A (en) * 1958-11-03 1961-03-14 Jersey Prod Res Co Petroleum recovery from carbonaceous formations
US2998457A (en) * 1958-11-19 1961-08-29 Ashland Oil Inc Production of phenols
US3036632A (en) * 1958-12-24 1962-05-29 Socony Mobil Oil Co Inc Recovery of hydrocarbon materials from earth formations by application of heat
US3097690A (en) * 1958-12-24 1963-07-16 Gulf Research Development Co Process for heating a subsurface formation
US3110345A (en) * 1959-02-26 1963-11-12 Gulf Research Development Co Low temperature reverse combustion process
US3113619A (en) * 1959-03-30 1963-12-10 Phillips Petroleum Co Line drive counterflow in situ combustion process
US3113623A (en) * 1959-07-20 1963-12-10 Union Oil Co Apparatus for underground retorting
US3181613A (en) * 1959-07-20 1965-05-04 Union Oil Co Method and apparatus for subterranean heating
US3116792A (en) * 1959-07-27 1964-01-07 Phillips Petroleum Co In situ combustion process
US3132692A (en) * 1959-07-27 1964-05-12 Phillips Petroleum Co Use of formation heat from in situ combustion
US3150715A (en) * 1959-09-30 1964-09-29 Shell Oil Co Oil recovery by in situ combustion with water injection
US3095031A (en) * 1959-12-09 1963-06-25 Eurenius Malte Oscar Burners for use in bore holes in the ground
US3131763A (en) * 1959-12-30 1964-05-05 Texaco Inc Electrical borehole heater
US3163745A (en) * 1960-02-29 1964-12-29 Socony Mobil Oil Co Inc Heating of an earth formation penetrated by a well borehole
US3127935A (en) * 1960-04-08 1964-04-07 Marathon Oil Co In situ combustion for oil recovery in tar sands, oil shales and conventional petroleum reservoirs
US3139928A (en) * 1960-05-24 1964-07-07 Shell Oil Co Thermal process for in situ decomposition of oil shale
US3106244A (en) * 1960-06-20 1963-10-08 Phillips Petroleum Co Process for producing oil shale in situ by electrocarbonization
US3142336A (en) * 1960-07-18 1964-07-28 Shell Oil Co Method and apparatus for injecting steam into subsurface formations
US3105545A (en) * 1960-11-21 1963-10-01 Shell Oil Co Method of heating underground formations
US3164207A (en) * 1961-01-17 1965-01-05 Wayne H Thessen Method for recovering oil
US3191679A (en) * 1961-04-13 1965-06-29 Wendell S Miller Melting process for recovering bitumens from the earth
US3207220A (en) * 1961-06-26 1965-09-21 Chester I Williams Electric well heater
US3114417A (en) * 1961-08-14 1963-12-17 Ernest T Saftig Electric oil well heater apparatus
US3057404A (en) * 1961-09-29 1962-10-09 Socony Mobil Oil Co Inc Method and system for producing oil tenaciously held in porous formations
US3183675A (en) * 1961-11-02 1965-05-18 Conch Int Methane Ltd Method of freezing an earth formation
US3209825A (en) * 1962-02-14 1965-10-05 Continental Oil Co Low temperature in-situ combustion
US3205946A (en) * 1962-03-12 1965-09-14 Shell Oil Co Consolidation by silica coalescence
US3149670A (en) * 1962-03-27 1964-09-22 Smclair Res Inc In-situ heating process
US3149672A (en) * 1962-05-04 1964-09-22 Jersey Prod Res Co Method and apparatus for electrical heating of oil-bearing formations
US3208531A (en) * 1962-08-21 1965-09-28 Otis Eng Co Inserting tool for locating and anchoring a device in tubing
US3182721A (en) * 1962-11-02 1965-05-11 Sun Oil Co Method of petroleum production by forward in situ combustion
US3205944A (en) * 1963-06-14 1965-09-14 Socony Mobil Oil Co Inc Recovery of hydrocarbons from a subterranean reservoir by heating
US6782947B2 (en) * 2001-04-24 2004-08-31 Shell Oil Company In situ thermal processing of a relatively impermeable formation to increase permeability of the formation
US6991036B2 (en) * 2001-04-24 2006-01-31 Shell Oil Company Thermal processing of a relatively permeable formation
US20040062340A1 (en) * 2002-09-16 2004-04-01 Peterson Otis G. Self-regulating nuclear power module

Cited By (82)

* Cited by examiner, † Cited by third party
Publication number Priority date Publication date Assignee Title
US8225866B2 (en) 2000-04-24 2012-07-24 Shell Oil Company In situ recovery from a hydrocarbon containing formation
US8789586B2 (en) 2000-04-24 2014-07-29 Shell Oil Company In situ recovery from a hydrocarbon containing formation
US8485252B2 (en) 2000-04-24 2013-07-16 Shell Oil Company In situ recovery from a hydrocarbon containing formation
US8579031B2 (en) 2003-04-24 2013-11-12 Shell Oil Company Thermal processes for subsurface formations
US7942203B2 (en) 2003-04-24 2011-05-17 Shell Oil Company Thermal processes for subsurface formations
US7987613B2 (en) * 2004-10-12 2011-08-02 Great River Energy Control system for particulate material drying apparatus and process
US8233782B2 (en) 2005-04-22 2012-07-31 Shell Oil Company Grouped exposed metal heaters
US8230927B2 (en) 2005-04-22 2012-07-31 Shell Oil Company Methods and systems for producing fluid from an in situ conversion process
US7866385B2 (en) 2006-04-21 2011-01-11 Shell Oil Company Power systems utilizing the heat of produced formation fluid
US10373928B1 (en) 2006-08-25 2019-08-06 Hypres, Inc. Method for electrically interconnecting at least two substrates and multichip module
US9647194B1 (en) 2006-08-25 2017-05-09 Hypres, Inc. Superconductive multi-chip module for high speed digital circuits
US20130067762A1 (en) * 2006-10-04 2013-03-21 Varco I/P, Inc. Reclamation of components of wellbore cuttings material
US8533974B2 (en) * 2006-10-04 2013-09-17 Varco I/P, Inc. Reclamation of components of wellbore cuttings material
US20080184587A1 (en) * 2007-02-02 2008-08-07 Shivvers Steve D High efficiency drier with multi stage heating and drying zones
US8196658B2 (en) 2007-10-19 2012-06-12 Shell Oil Company Irregular spacing of heat sources for treating hydrocarbon containing formations
US9528322B2 (en) 2008-04-18 2016-12-27 Shell Oil Company Dual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations
US8162405B2 (en) 2008-04-18 2012-04-24 Shell Oil Company Using tunnels for treating subsurface hydrocarbon containing formations
US8562078B2 (en) 2008-04-18 2013-10-22 Shell Oil Company Hydrocarbon production from mines and tunnels used in treating subsurface hydrocarbon containing formations
US8151907B2 (en) 2008-04-18 2012-04-10 Shell Oil Company Dual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations
US8172335B2 (en) 2008-04-18 2012-05-08 Shell Oil Company Electrical current flow between tunnels for use in heating subsurface hydrocarbon containing formations
US8636323B2 (en) 2008-04-18 2014-01-28 Shell Oil Company Mines and tunnels for use in treating subsurface hydrocarbon containing formations
US8752904B2 (en) 2008-04-18 2014-06-17 Shell Oil Company Heated fluid flow in mines and tunnels used in heating subsurface hydrocarbon containing formations
US8177305B2 (en) 2008-04-18 2012-05-15 Shell Oil Company Heater connections in mines and tunnels for use in treating subsurface hydrocarbon containing formations
US8220539B2 (en) 2008-10-13 2012-07-17 Shell Oil Company Controlling hydrogen pressure in self-regulating nuclear reactors used to treat a subsurface formation
US20100101794A1 (en) * 2008-10-13 2010-04-29 Robert Charles Ryan Heating subsurface formations with fluids
US8261832B2 (en) 2008-10-13 2012-09-11 Shell Oil Company Heating subsurface formations with fluids
US8267170B2 (en) 2008-10-13 2012-09-18 Shell Oil Company Offset barrier wells in subsurface formations
US8353347B2 (en) 2008-10-13 2013-01-15 Shell Oil Company Deployment of insulated conductors for treating subsurface formations
US9051829B2 (en) 2008-10-13 2015-06-09 Shell Oil Company Perforated electrical conductors for treating subsurface formations
US8881806B2 (en) 2008-10-13 2014-11-11 Shell Oil Company Systems and methods for treating a subsurface formation with electrical conductors
US9129728B2 (en) 2008-10-13 2015-09-08 Shell Oil Company Systems and methods of forming subsurface wellbores
US8281861B2 (en) 2008-10-13 2012-10-09 Shell Oil Company Circulated heated transfer fluid heating of subsurface hydrocarbon formations
US8267185B2 (en) 2008-10-13 2012-09-18 Shell Oil Company Circulated heated transfer fluid systems used to treat a subsurface formation
US8448707B2 (en) 2009-04-10 2013-05-28 Shell Oil Company Non-conducting heater casings
US8434555B2 (en) 2009-04-10 2013-05-07 Shell Oil Company Irregular pattern treatment of a subsurface formation
US8327932B2 (en) 2009-04-10 2012-12-11 Shell Oil Company Recovering energy from a subsurface formation
US8851170B2 (en) 2009-04-10 2014-10-07 Shell Oil Company Heater assisted fluid treatment of a subsurface formation
US9494326B2 (en) 2009-10-07 2016-11-15 Mark Collins Apparatus for generating heat
US20120286054A1 (en) * 2009-10-07 2012-11-15 Mark Collins Apparatus for generating heat
US9466896B2 (en) 2009-10-09 2016-10-11 Shell Oil Company Parallelogram coupling joint for coupling insulated conductors
US8485847B2 (en) 2009-10-09 2013-07-16 Shell Oil Company Press-fit coupling joint for joining insulated conductors
US8356935B2 (en) 2009-10-09 2013-01-22 Shell Oil Company Methods for assessing a temperature in a subsurface formation
US8816203B2 (en) 2009-10-09 2014-08-26 Shell Oil Company Compacted coupling joint for coupling insulated conductors
US8257112B2 (en) 2009-10-09 2012-09-04 Shell Oil Company Press-fit coupling joint for joining insulated conductors
US8701769B2 (en) 2010-04-09 2014-04-22 Shell Oil Company Methods for treating hydrocarbon formations based on geology
US8485256B2 (en) 2010-04-09 2013-07-16 Shell Oil Company Variable thickness insulated conductors
US8820406B2 (en) 2010-04-09 2014-09-02 Shell Oil Company Electrodes for electrical current flow heating of subsurface formations with conductive material in wellbore
US8833453B2 (en) 2010-04-09 2014-09-16 Shell Oil Company Electrodes for electrical current flow heating of subsurface formations with tapered copper thickness
US8739874B2 (en) 2010-04-09 2014-06-03 Shell Oil Company Methods for heating with slots in hydrocarbon formations
US8859942B2 (en) 2010-04-09 2014-10-14 Shell Oil Company Insulating blocks and methods for installation in insulated conductor heaters
US8502120B2 (en) 2010-04-09 2013-08-06 Shell Oil Company Insulating blocks and methods for installation in insulated conductor heaters
US8701768B2 (en) 2010-04-09 2014-04-22 Shell Oil Company Methods for treating hydrocarbon formations
US8939207B2 (en) 2010-04-09 2015-01-27 Shell Oil Company Insulated conductor heaters with semiconductor layers
US9399905B2 (en) 2010-04-09 2016-07-26 Shell Oil Company Leak detection in circulated fluid systems for heating subsurface formations
US8967259B2 (en) 2010-04-09 2015-03-03 Shell Oil Company Helical winding of insulated conductor heaters for installation
US9127523B2 (en) 2010-04-09 2015-09-08 Shell Oil Company Barrier methods for use in subsurface hydrocarbon formations
US9022109B2 (en) 2010-04-09 2015-05-05 Shell Oil Company Leak detection in circulated fluid systems for heating subsurface formations
US9033042B2 (en) 2010-04-09 2015-05-19 Shell Oil Company Forming bitumen barriers in subsurface hydrocarbon formations
US8631866B2 (en) 2010-04-09 2014-01-21 Shell Oil Company Leak detection in circulated fluid systems for heating subsurface formations
US9127538B2 (en) 2010-04-09 2015-09-08 Shell Oil Company Methodologies for treatment of hydrocarbon formations using staged pyrolyzation
US8857051B2 (en) 2010-10-08 2014-10-14 Shell Oil Company System and method for coupling lead-in conductor to insulated conductor
US8586866B2 (en) 2010-10-08 2013-11-19 Shell Oil Company Hydroformed splice for insulated conductors
US8586867B2 (en) 2010-10-08 2013-11-19 Shell Oil Company End termination for three-phase insulated conductors
US9755415B2 (en) 2010-10-08 2017-09-05 Shell Oil Company End termination for three-phase insulated conductors
US9337550B2 (en) 2010-10-08 2016-05-10 Shell Oil Company End termination for three-phase insulated conductors
US8943686B2 (en) 2010-10-08 2015-02-03 Shell Oil Company Compaction of electrical insulation for joining insulated conductors
US8732946B2 (en) 2010-10-08 2014-05-27 Shell Oil Company Mechanical compaction of insulator for insulated conductor splices
US10226401B2 (en) 2010-12-29 2019-03-12 Cardinal Health 414, Llc Closed vial fill system for aseptic dispensing
US9139316B2 (en) 2010-12-29 2015-09-22 Cardinal Health 414, Llc Closed vial fill system for aseptic dispensing
US9016370B2 (en) 2011-04-08 2015-04-28 Shell Oil Company Partial solution mining of hydrocarbon containing layers prior to in situ heat treatment
WO2013012822A1 (en) * 2011-07-15 2013-01-24 Cardinal Health 414, Llc Systems, methods, and devices for producing, manufacturing, and control of radiopharmaceuticals
US9480962B2 (en) 2011-07-15 2016-11-01 Cardinal Health 414, Llc Modular cassette synthesis unit
US9417332B2 (en) 2011-07-15 2016-08-16 Cardinal Health 414, Llc Radiopharmaceutical CZT sensor and apparatus
US10906020B2 (en) 2011-07-15 2021-02-02 Cardinal Health 414, Llc Systems, methods and devices for producing, manufacturing and control of radiopharmaceuticals
US9309755B2 (en) 2011-10-07 2016-04-12 Shell Oil Company Thermal expansion accommodation for circulated fluid systems used to heat subsurface formations
US10047594B2 (en) 2012-01-23 2018-08-14 Genie Ip B.V. Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation
US9605524B2 (en) 2012-01-23 2017-03-28 Genie Ip B.V. Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation
US10210961B2 (en) * 2012-05-11 2019-02-19 Ge-Hitachi Nuclear Energy Americas, Llc System and method for a commercial spent nuclear fuel repository turning heat and gamma radiation into value
US20130301767A1 (en) * 2012-05-11 2013-11-14 Ge-Hitachi Nuclear Energy Americas, Llc System and method for a commercial spent nuclear fuel repository turning heat and gamma radiation into value
US11289237B2 (en) 2012-05-11 2022-03-29 Ge-Hitachi Nuclear Energy Americas, Llc System for spent nuclear fuel storage
US11638331B2 (en) 2018-05-29 2023-04-25 Kontak LLC Multi-frequency controllers for inductive heating and associated systems and methods
US11555473B2 (en) 2018-05-29 2023-01-17 Kontak LLC Dual bladder fuel tank

Also Published As

Publication number Publication date
EP2334900A1 (en) 2011-06-22
CN102187052B (zh) 2015-01-07
WO2010045115A3 (en) 2010-06-24
US20160281482A1 (en) 2016-09-29
CA2738805A1 (en) 2010-04-22
US8281861B2 (en) 2012-10-09
RU2011119095A (ru) 2012-11-20
BRPI0919775A2 (pt) 2017-06-27
RU2537712C2 (ru) 2015-01-10
IL211991A0 (en) 2011-06-30
IL211990A0 (en) 2011-06-30
IL211950A0 (en) 2011-06-30
RU2524584C2 (ru) 2014-07-27
US20100096137A1 (en) 2010-04-22
US8256512B2 (en) 2012-09-04
EP2334901A1 (en) 2011-06-22
US9129728B2 (en) 2015-09-08
RU2518649C2 (ru) 2014-06-10
RU2011119093A (ru) 2012-11-20
US20100089584A1 (en) 2010-04-15
JP5611961B2 (ja) 2014-10-22
US20100108379A1 (en) 2010-05-06
JP2012509416A (ja) 2012-04-19
JP2012509415A (ja) 2012-04-19
CN102187055B (zh) 2014-09-10
EP2361344A1 (en) 2011-08-31
WO2010045102A1 (en) 2010-04-22
JP2012509417A (ja) 2012-04-19
US20100101794A1 (en) 2010-04-29
CA2738939A1 (en) 2010-04-22
US8267185B2 (en) 2012-09-18
CN102187052A (zh) 2011-09-14
IL211950A (en) 2013-11-28
CA2739039A1 (en) 2010-04-22
BRPI0920141A2 (pt) 2017-06-27
CN102187053A (zh) 2011-09-14
CA2739086A1 (en) 2010-04-22
CA2739039C (en) 2018-01-02
CN102187054A (zh) 2011-09-14
US20100206570A1 (en) 2010-08-19
WO2010045098A1 (en) 2010-04-22
US8267170B2 (en) 2012-09-18
WO2010045115A2 (en) 2010-04-22
IL211951A0 (en) 2011-06-30
RU2518700C2 (ru) 2014-06-10
CN102187055A (zh) 2011-09-14
AU2009303606A1 (en) 2010-04-22
US20100101784A1 (en) 2010-04-29
AU2009303608A1 (en) 2010-04-22
RU2011119086A (ru) 2012-11-20
AU2009303605A1 (en) 2010-04-22
WO2010045101A1 (en) 2010-04-22
US9051829B2 (en) 2015-06-09
AU2009303609B2 (en) 2014-07-17
US20100108310A1 (en) 2010-05-06
US9022118B2 (en) 2015-05-05
RU2011119096A (ru) 2012-11-20
IL211991A (en) 2014-12-31
AU2009303605B2 (en) 2013-10-03
AU2009303610A1 (en) 2010-04-22
US20100155070A1 (en) 2010-06-24
WO2010045099A1 (en) 2010-04-22
US20100147521A1 (en) 2010-06-17
JP5611963B2 (ja) 2014-10-22
RU2011119081A (ru) 2012-11-20
EP2361343A1 (en) 2011-08-31
JP2012508838A (ja) 2012-04-12
WO2010045103A1 (en) 2010-04-22
US20100147522A1 (en) 2010-06-17
IL211951A (en) 2013-10-31
US8261832B2 (en) 2012-09-11
JP2012509418A (ja) 2012-04-19
CN102203377A (zh) 2011-09-28
IL211990A (en) 2013-11-28
JP5611962B2 (ja) 2014-10-22
EP2334894A1 (en) 2011-06-22
CA2739088A1 (en) 2010-04-22
AU2009303608B2 (en) 2013-11-14
RU2530729C2 (ru) 2014-10-10
US8881806B2 (en) 2014-11-11
IL211989A0 (en) 2011-06-30
US20100089586A1 (en) 2010-04-15
US8353347B2 (en) 2013-01-15
WO2010045097A1 (en) 2010-04-22
IL211989A (en) 2014-12-31
RU2529537C2 (ru) 2014-09-27
EP2361342A1 (en) 2011-08-31
CA2738804A1 (en) 2010-04-22
AU2009303606B2 (en) 2013-12-05
JP2012509419A (ja) 2012-04-19
CN102187054B (zh) 2014-08-27
US20100224368A1 (en) 2010-09-09
AU2009303604A1 (en) 2010-04-22
US8220539B2 (en) 2012-07-17
RU2011119084A (ru) 2012-11-20
AU2009303609A1 (en) 2010-04-22
AU2009303604B2 (en) 2013-09-26

Similar Documents

Publication Publication Date Title
US8267170B2 (en) Offset barrier wells in subsurface formations
US8434555B2 (en) Irregular pattern treatment of a subsurface formation
US9528322B2 (en) Dual motor systems and non-rotating sensors for use in developing wellbores in subsurface formations

Legal Events

Date Code Title Description
AS Assignment

Owner name: SHELL OIL COMPANY,TEXAS

Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNORS:VINEGAR, HAROLD J;NGUYEN, SCOTT VINH;SIGNING DATES FROM 20091217 TO 20100108;REEL/FRAME:023761/0913

STCB Information on status: application discontinuation

Free format text: ABANDONED -- FAILURE TO RESPOND TO AN OFFICE ACTION