WO2003036043A2 - Forming openings in a hydrocarbon containing formation using magnetic tracking - Google Patents
Forming openings in a hydrocarbon containing formation using magnetic tracking Download PDFInfo
- Publication number
- WO2003036043A2 WO2003036043A2 PCT/US2002/034272 US0234272W WO03036043A2 WO 2003036043 A2 WO2003036043 A2 WO 2003036043A2 US 0234272 W US0234272 W US 0234272W WO 03036043 A2 WO03036043 A2 WO 03036043A2
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- opening
- magnetic
- formation
- openings
- magnets
- Prior art date
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Classifications
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B09—DISPOSAL OF SOLID WASTE; RECLAMATION OF CONTAMINATED SOIL
- B09C—RECLAMATION OF CONTAMINATED SOIL
- B09C1/00—Reclamation of contaminated soil
- B09C1/02—Extraction using liquids, e.g. washing, leaching, flotation
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B09—DISPOSAL OF SOLID WASTE; RECLAMATION OF CONTAMINATED SOIL
- B09C—RECLAMATION OF CONTAMINATED SOIL
- B09C1/00—Reclamation of contaminated soil
- B09C1/06—Reclamation of contaminated soil thermally
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G45/00—Refining of hydrocarbon oils using hydrogen or hydrogen-generating compounds
-
- C—CHEMISTRY; METALLURGY
- C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
- C10G—CRACKING HYDROCARBON OILS; PRODUCTION OF LIQUID HYDROCARBON MIXTURES, e.g. BY DESTRUCTIVE HYDROGENATION, OLIGOMERISATION, POLYMERISATION; RECOVERY OF HYDROCARBON OILS FROM OIL-SHALE, OIL-SAND, OR GASES; REFINING MIXTURES MAINLY CONSISTING OF HYDROCARBONS; REFORMING OF NAPHTHA; MINERAL WAXES
- C10G9/00—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils
- C10G9/24—Thermal non-catalytic cracking, in the absence of hydrogen, of hydrocarbon oils by heating with electrical means
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/166—Injecting a gaseous medium; Injecting a gaseous medium and a liquid medium
- E21B43/168—Injecting a gaseous medium
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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 DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/243—Combustion in situ
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
- E21B43/305—Specific pattern of wells, e.g. optimizing the spacing of wells comprising at least one inclined or horizontal well
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
- E21B47/02—Determining slope or direction
- E21B47/022—Determining slope or direction of the borehole, e.g. using geomagnetism
- E21B47/0224—Determining slope or direction of the borehole, e.g. using geomagnetism using seismic or acoustic means
-
- G—PHYSICS
- G01—MEASURING; TESTING
- G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
- G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
- G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
- G01V3/26—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device
-
- B—PERFORMING OPERATIONS; TRANSPORTING
- B09—DISPOSAL OF SOLID WASTE; RECLAMATION OF CONTAMINATED SOIL
- B09C—RECLAMATION OF CONTAMINATED SOIL
- B09C2101/00—In situ
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B17/00—Drilling rods or pipes; Flexible drill strings; Kellies; Drill collars; Sucker rods; Cables; Casings; Tubings
- E21B17/02—Couplings; joints
- E21B17/028—Electrical or electro-magnetic connections
- E21B17/0285—Electrical or electro-magnetic connections characterised by electrically insulating elements
-
- 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
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P30/00—Technologies relating to oil refining and petrochemical industry
-
- 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
- Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
- Y02P—CLIMATE CHANGE MITIGATION TECHNOLOGIES IN THE PRODUCTION OR PROCESSING OF GOODS
- Y02P30/00—Technologies relating to oil refining and petrochemical industry
- Y02P30/40—Ethylene production
-
- 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
- Y10S—TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
- Y10S210/00—Liquid purification or separation
- Y10S210/901—Specified land fill feature, e.g. prevention of ground water fouling
-
- 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
- Y10T137/00—Fluid handling
- Y10T137/0318—Processes
- Y10T137/0391—Affecting flow by the addition of material or energy
Definitions
- the present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations. Certain embodiments relate to methods and systems for forming openings or wellbores in hydrocarbon containing formations using magnetic tracking.
- Hydrocarbons obtained from subterranean (e.g., sedimentary) formations are often used as energy resources, as feedstocks, and as consumer products.
- Concerns over depletion of available hydrocarbon resources and 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.
- Chemical and/or physical properties of hydrocarbon material within a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation.
- 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 within the formation.
- 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.
- U.S. Patent No. 5,485,089 to Kuckes and U.S. Patent No. RE36,569 to Kuckes describe a method for determining distance from a borehole to a nearby, substantially parallel target well for use in guiding the drilling of the borehole.
- the method includes positioning a magnetic field sensor in the borehole at a known depth and providing a magnetic field source in the target well.
- U.S. Patent Nos. 5,515,931 to Kuckes and 5,657,826 to Kuckes describe a single guide wire system for use in continually directional drilling of boreholes.
- the system includes a guide wire extending generally parallel to the desired path of the borehole.
- U.S. Patent No. 5,725,059 to Kuckes et al. describes a method and apparatus for steering boreholes for use in creating a subsurface barrier layer.
- the method includes drilling a first reference borehole, retracting the drill stem while injecting a sealing material into the earth around the borehole, and simultaneously pulling a guide wire into the borehole.
- the guide wire is used to produce a corresponding magnetic field in the earth around the reference borehole.
- the vector components of the magnetic field are used to determine the distance and direction from the borehole being drilled to the reference borehole in order to steer the borehole being drilled.
- the distances between adjacent wellbores may need to be maintained at a selected distance and within certain tolerances. If the selected distance between wellbores is not maintained within the tolerances, the wellbores may not be useable or may have to be redrilled or modified, which can be very costly. Thus, techniques are needed for forming wellbores at selected distances within specified tolerances. These techniques also need to be reliable and useable for forming a variety of wellbores, which may be formed at various angles in a formation.
- one or more openings may be formed in a hydrocarbon containing formation.
- a first opening may be formed in the formation.
- a plurality of magnets may be provided to the first opening.
- the plurality of magnets may be positioned along a portion of the first opening.
- the plurality of magnets may produce a series of magnetic fields along the portion of the first opening.
- a second opening may be formed in the formation using magnetic tracking of the series of magnetic fields produced by the plurality of magnets in the first opening. Magnetic tracking may be used to form the second opening a desired distance from the first opening. In certain embodiments, the deviation in spacing between the first opening and the second opening may be less than or equal to about ⁇ 1 m for every 500 m of length of the openings.
- the plurality of magnets may form a magnetic string.
- the magnetic string may include one or more magnetic segments.
- each magnetic segment may include a plurality of magnets.
- the magnetic segments may include an effective north pole and an effective south pole.
- two adjacent magnetic segments are positioned with opposing poles to form a junction of opposing poles.
- Multiple openings may be formed in a hydrocarbon containing formation.
- the multiple openings may form a pattern of openings.
- a first opening may be formed in the formation.
- a magnetic string may be placed in the first opening to produce magnetic fields in a portion of the formation.
- a first set of openings may be formed using magnetic tracking of the magnetic string.
- the magnetic string may be moved to a first opening in the first set of openings.
- a second set of openings may be formed using magnetic tracking of the magnetic string located in the first opening in the first set of openings.
- a third set of openings may be formed by using magnetic tracking of the magnetic string, where the magnetic string is located in an opening in the second set of openings.
- a third set of openings may be formed by using magnetic tracking of the magnetic string, where the magnetic string is located in another opening in the first set of openings.
- a system for forming openings in a hydrocarbon containing formation may include a drilling apparatus, a magnetic string, and a sensor.
- the magnetic string may include two or more magnetic segments positioned within a conduit. Each of the magnetic segments may include a plurality of magnets.
- the sensor may be used to detect magnetic fields within the formation produced by the magnetic string.
- the magnetic string may be placed in a first opening and the drilling apparatus and sensor in a second opening.
- FIG. 1 depicts an illustration of stages of heating a hydrocarbon containing formation.
- FIG. 2 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation.
- FIG. 3 depicts an embodiment of a heater well.
- FIG. 4 depicts an embodiment of a heater well.
- FIG. 5 depicts an embodiment of a heater well.
- FIG. 6 illustrates a schematic view of multiple heaters branched from a single well in a hydrocarbon containing formation.
- FIG. 7 illustrates a schematic of an elevated view of multiple heaters branched from a single well in a hydrocarbon containing formation.
- FIG. 8 depicts an embodiment of heater wells located in a hydrocarbon containing formation.
- FIG. 9 depicts an embodiment of a pattern of heater wells in a hydrocarbon containing formation.
- FIGS. 10, 11, and 12 show magnetic field components as a function of hole depth in neighboring observation wells.
- FIG. 13 shows magnetic field components for a build-up section of a wellbore.
- FIG. 14 depicts a ratio of magnetic field components for a build-up section of a wellbore.
- FIG. 15 depicts a ratio of magnetic field components for a build-up section of a wellbore.
- FIGS. 16, 17, 18, and 19 depict comparisons of actual calculated magnetic field components versus modeled magnetic field components.
- FIG. 20 depicts a schematic representation of an embodiment of a magnetostatic drilling operation.
- FIG. 21 depicts an embodiment of a section of a conduit with two magnetic segments.
- FIG. 22 depicts a schematic of a portion of a magnetic string.
- the following description generally relates to systems and methods for treating a hydrocarbon containing formation (e.g., a formation containing coal (including lignite, sapropelic coal, etc.), oil shale, carbonaceous shale, shungites, kerogen, bitumen, oil, kerogen and oil in a low permeability matrix, heavy hydrocarbons, asphaltites, natural mineral waxes, formations wherein kerogen is blocking production of other hydrocarbons, etc.).
- a hydrocarbon containing formation e.g., a formation containing coal (including lignite, sapropelic coal, etc.), oil shale, carbonaceous shale, shungites, kerogen, bitumen, oil, kerogen and oil in a low permeability matrix, heavy hydrocarbons, asphaltites, natural mineral waxes, formations wherein kerogen is blocking production of other hydrocarbons, etc.
- Such formations may be treated to yield relatively high quality hydrocarbon products,
- 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 within or adjacent to mineral matrices within 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 (e.g., hydrogen ("H 2 "), nitrogen (“N 2 "), carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia).
- non-hydrocarbon fluids e.g., hydrogen ("H 2 "), nitrogen (“N 2 "), carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia.
- a “formation” includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden.
- An “overburden” and/or an “underburden” generally includes one or more different types of impermeable materials.
- overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate (i.e., an impermeable carbonate without hydrocarbons).
- an overburden and/or an underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ conversion processing that results in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or underburden.
- an underburden may contain shale or mudstone.
- the overburden and/or underburden may be somewhat permeable.
- formation fluids and “produced fluids” refer to fluids removed from a hydrocarbon containing formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water (steam).
- mobilized fluid refers to fluids within the formation that are able to flow because of thermal treatment of the formation. Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids.
- a “heat source” is any system for providing heat to at least a portion of a formation substantially b> conductive and/or radiative heat transfer.
- a heat source may include electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed within a conduit.
- a heat source may also include heat sources that generate heat by burning a fuel external to or within a formation, such as 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 transfer media 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 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 (e.g., chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy).
- a chemical reaction may include an exothermic reaction (e.g., an oxidation reaction).
- a heat source may include 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 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 (e.g., natural distributed combustors), and/or combinations thereof.
- a “unit of heat sources” refers to a number of heat sources that form a template that is repeated to create a pattern of heat sources within a formation.
- 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 other cross-sectional shapes (e.g., circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes).
- the terms "well” and “opening,” when referring to an opening in the formation may be used interchangeably with the term “wellbore.”
- “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.
- pyrolysis zone refers to a volume of a formation (e.g., a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.
- Condensable hydrocarbons are hydrocarbons that condense at 25 °C at 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.
- FIG. 1 illustrates several stages of heating a hydrocarbon containing formation.
- FIG. 1 also depicts an example of yield (barrels of oil equivalent per ton) (y axis) of formation fluids from a hydrocarbon containing formation versus temperature (°C) (x axis) of the formation (as the formation is heated at a relatively low rate).
- Desorption of methane and vaporization of water occurs during stage 1 heating. Heating of the formation through stage 1 may be performed as quickly as possible. For example, when a hydrocarbon containing formation is initially heated, hydrocarbons in the formation may desorb adsorbed methane. The desorbed methane may be produced from the formation. If the hydrocarbon containing formation is heated further, water within the hydrocarbon containing formation may be vaporized. Water may occupy, in some hydrocarbon containing formations, between about 10 % and about 50 % of the pore volume in the formation. In other formations, water may occupy larger or smaller portions of the pore volume. Water typically is vaporized in a formation between about 160 °C and about 285 °C for pressures of about 6 bars absolute to 70 bars absolute.
- the vaporized water may produce wettability changes in the formation and/or increase formation pressure.
- the wettability changes and/or increased pressure may affect pyrolysis reactions or other reactions in the formation.
- the vaporized water may be produced from the formation.
- the vaporized water may be used for steam extraction and/or distillation in the formation or outside the formation. Removing the water from and increasing the pore volume in the formation may increase the storage space for hydrocarbons within the pore volume.
- a temperature within the formation reaches (at least) an initial pyrolyzation temperature (e.g., a temperature at the lower end of the temperature range shown as stage 2).
- Hydrocarbons within the formation may be pyrolyzed throughout stage 2.
- a pyrolysis temperature range may vary depending on types of hydrocarbons within the formation.
- a pyrolysis temperature range may include temperatures between about 250 °C and about 900 °C.
- a pyrolysis temperature range for producing desired products may extend through only a portion of the total pyrolysis temperature range.
- a pyrolysis temperature range for producing desired products may include temperatures between about 250 °C and about 400 °C.
- a temperature of hydrocarbons in a formation is slowly raised through a temperature range from about 250 °C to about 400 °C
- production of pyrolysis products may be substantially complete when the temperature approaches 400 °C.
- Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that slowly raise the temperature of hydrocarbons in the formation through a pyrolysis temperature range.
- a temperature of the hydrocarbons to be subjected to pyrolysis may not be slowly increased throughout a temperature range from about 250 °C to about 400 °C.
- the hydrocarbons in the formation may be heated to a desired temperature (e.g., about 325 °C). Other temperatures may be selected as the desired temperature.
- Superposition of heat from heat sources may allow 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 the desired temperature.
- the hydrocarbons may be maintained substantially at the desired temperature until pyrolysis declines such that production of desired formation fluids from the formation becomes uneconomical.
- Formation fluids including pyrolyzation fluids may be produced from the formation.
- the pyrolyzation fluids may include, but are not limited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide, hydrogen sulfide, ammonia, nitrogen, water, and mixtures thereof.
- hydrocarbons hydrogen, carbon dioxide, carbon monoxide, hydrogen sulfide, ammonia, nitrogen, water, and mixtures thereof.
- the formation may produce mostly methane and/or hydrogen. If a hydrocarbon containing formation is heated throughout an entire pyrolysis range, the formation may produce only small amounts of hydrogen towards an upper limit of the pyrolysis range. After all of the available hydrogen is depleted, a minimal amount of fluid production from the formation will typically occur.
- Synthesis gas generation may take place during stage 3 heating depicted in FIG. 1.
- Stage 3 may include heating a hydrocarbon containing formation to a temperature sufficient to allow synthesis gas generation
- the temperature of the formation when the synthesis gas generating fluid is introduced to the formation may determine the composition of synthesis gas produced within the formation. If a synthesis gas generating fluid . is introduced into a formation at a temperature sufficient to allow synthesis gas generation, synthesis gas may be generated within the formation.
- the generated synthesis gas may be removed from the formation through a production well or production wells. A large volume of synthesis gas may be produced during generation of synthesis gas.
- FIG. 2 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation.
- Heat sources 100 may be placed within at least a portion of the hydrocarbon containing formation.
- Heat sources 100 may include, for example, electric heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 100 may also include other types of heaters.
- Heat sources 100 may provide heat to at least a portion of a hydrocarbon containing formation.
- Energy may be supplied to the heat sources 100 through supply lines 102.
- the supply lines may be structurally different depending on the type of heat source or heat sources being used to heat the formation.
- Supply lines for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated within the formation.
- Production wells 104 may be used to remove formation fluid from the formation. Formation fluid produced from production wells 104 may be transported through collection piping 106 to treatment facilities 108. Formation fluids may also be produced from heat sources 100. For example, fluid may be produced from heat sources 100 to control pressure within the formation adjacent to the heat sources. Fluid produced from heat sources 100 may be transported through tubing or piping to collection piping 106 or the produced fluid may be transported through tubing or piping directly to treatment facilities 108. Treatment facilities 108 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and other systems and units for processing produced formation fluids.
- An in situ conversion system for treating hydrocarbons may include barrier wells 110.
- barrier wells 1 10 may include freeze wells.
- barriers may be used to inhibit migration of fluids (e.g., generated fluids and/or groundwater) into and/or out of a portion of a formation undergoing an in situ conversion process.
- Barriers may include, but are not limited to naturally occurring portions (e.g., overburden and/or underburden), freeze wells, frozen barrier zones, low temperature barrier zones, grout walls, sulfur wells, dewatering wells, injection wells, 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, sheets driven into the formation, or combinations thereof.
- naturally occurring portions e.g., overburden and/or underburden
- freeze wells e.g., frozen barrier zones, low temperature barrier zones, grout walls, sulfur wells, dewatering wells, injection wells, 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, sheets driven into the formation, or combinations thereof.
- Hydrocarbons to be subjected to in situ conversion may be located under a large area.
- the in situ conversion system may be used to treat small portions of the formation, and other sections of the formation may be treated over time.
- a field layout for 24 years of development may be divided into 24 individual plots that represent individual drilling years.
- Each plot may include 120 "tiles" (repeating matrix patterns) wherein each plot is made of 6 rows by 20 columns of tiles.
- Each tile may include 1 production well and 12 or 18 heater wells.
- the heater wells may be placed in an equilateral triangle pattern with a well spacing of about 12 m.
- Production wells may be located in centers of equilateral triangles of heater wells, or the production wells may be located approximately at a midpoint between two adjacent heater wells.
- heat sources will be placed within a heater well formed within a hydrocarbon containing formation.
- the heater well may include an opening through an overburden of the formation.
- the heater may extend into or through at least one hydrocarbon containing section (or hydrocarbon containing layer) of the formation.
- an embodiment of heater well 130 may include an opening in hydrocarbon layer 124 that has a helical or spiral shape.
- a spiral heater well may increase contact with the formation as opposed to a vertically positioned heater.
- a spiral heater well may provide expansion room that inhibits buckling or other modes of failure when the heater well is heated or cooled.
- heater wells may include substantially straight sections through overburden 126. Use of a straight section of heater well through the overburden may decrease heat loss to the overburden and reduce the cost of the heater well.
- Heater well 130 may be substantially "U” shaped. The legs of the "U” may be wider or more narrow depending on the particular heater well and formation characteristics.
- First portion 132 and third portion 134 of heater well 130 may be arranged substantially perpendicular to an upper surface of hydrocarbon layer 124 in some embodiments. In addition, the first and the third portion of the heater well may extend substantially vertically through overburden 126. Second portion 136 of heater well 130 may be substantially parallel to the upper surface of the hydrocarbon layer.
- heat sources 100 may extend from a heater well in some embodiments. As shown in FIG. 5, heat sources 100 extend through overburden 126 into hydrocarbon layer 124 from heater well 130. Multiple wells extending from a single wellbore may be used when surface considerations (e.g., aesthetics, surface land use concerns, and/or unfavorable soil conditions near the surface) make it desirable to concentrate well platforms in a small area. For example, in areas where the soil is frozen and/or marshy, it may be more cost-effective to have a minimal number of well platforms located at selected sites.
- surface considerations e.g., aesthetics, surface land use concerns, and/or unfavorable soil conditions near the surface
- FIG. 6 illustrates a schematic of view of multilateral or side tracked lateral heaters branched from a single well in a hydrocarbon containing formation.
- a hydrocarbon containing formation e.g., in a coal, oil shale, or tar sands formation
- Heat provided to a thin layer with a low thermal conductivity from a horizontal wellbore may be more effectively trapped within the thin layer and reduce heat losses from the layer.
- Substantially vertical opening 146 may be placed in hydrocarbon layer 124.
- Substantially vertical opening 146 may be an elongated portion of an opening formed in hydrocarbon layer 124.
- Hydrocarbon layer 124 may be below overburden 126.
- One or more substantially horizontal openings 138 may also be placed in hydrocarbon layer 124.
- Horizontal openings 138 may, in some embodiments, contain perforated liners.
- Horizontal openings 138 may be coupled to vertical opening 146.
- Horizontal openings 138 may be elongated portions that diverge from the elongated portion of vertical opening 146.
- Horizontal openings 138 may be formed in hydrocarbon layer 124 after vertical opening 146 has been formed. In certain embodiments, openings 138 may be angled upwards to facilitate flow of formation fluids towards the production conduit.
- Each horizontal opening 138 may lie above or below an adjacent horizontal opening.
- six horizontal openings 138 may be formed in hydrocarbon layer 124.
- Three horizontal openings 138 may face 180°, or in a substantially opposite direction, from three additional horizontal openings 138.
- Two horizontal openings facing substantially opposite directions may lie in a substantially identical vertical plane within the formation.
- Any number of horizontal openings 138 may be coupled to a single vertical opening 146, depending on, but not limited to, a thickness of hydrocarbon layer 124, a type of formation, a desired heating rate in the formation, and a desired production rate.
- Production conduit 142 may be placed substantially vertically within vertical opening 146.
- Production conduit 142 may be substantially centered within vertical opening 146.
- Pump 144 may be coupled to production conduit 142.
- Such pump may be used, in some embodiments, to pump formation fluids from the bottom of the well.
- Pump 144 may be a rod pump, progressing cavity pump (PCP), centrifugal pump, jet pump, gas lift pump, submersible pump, rotary pump, etc.
- One or more heaters 140 may be placed within each horizontal opening 138. Heaters 140 may be placed in hydrocarbon layer 124 through vertical opening 146 and into horizontal opening 138.
- heater 140 may be used to generate heat along a length of the heater within vertical opening 146 and horizontal opening 138. In other embodiments, heater 140 may be used to generate heat only within horizontal opening 138. In certain embodiments, heat generated by heater 140 may be varied along its length and/or varied between vertical opening 146 and horizontal opening 138. For example, less heat may be generated by heater 140 in vertical opening 146 and more heat may be generated by the heater in horizontal opening 138. It may be advantageous to have at least some heating within vertical opening 146. This may maintain fluids produced from the formation in a vapor phase in production conduit 142 and or may upgrade the produced fluids within the production well. Having production conduit 142 and heaters 140 installed into a formation through a single opening in the formation may reduce costs associated with forming openings in the formation and installing production equipment and heaters within the formation.
- FIG. 7 depicts a schematic view from an elevated position of the embodiment of FIG. 6.
- One or more vertical openings 146 may be formed in hydrocarbon layer 124. Each of vertical openings 146 may lie along a single plane in hydrocarbon layer 124.
- Horizontal openings 138 may extend in a plane substantially perpendicular to the plane of vertical openings 146. Additional horizontal openings 138 may lie in a plane below the horizontal openings as shown in the schematic depiction of FIG. 6.
- a number of vertical openings 146 and/or a spacing between vertical openings 146 may be determined by, for example, a desired heating rate or a desired production rate. In some embodiments, spacing between vertical openings may be about 4 m to about 30 m. Longer or shorter spacings may be used to meet specific formation needs.
- a length of a horizontal opening 138 may be up to about 1600 m. However, a length of horizontal openings 138 may vary depending on, for example, a maximum installation cost, an area of hydrocarbon layer 124, or
- a formation having one or more thin hydrocarbon layers may be treated.
- the hydrocarbon layer may be, but is not limited to, a rich, thin coal seam; a rich, thin oil shale; or a relatively thin hydrocarbon layer in a tar sands formation.
- such formations may be treated with heat sources that are positioned substantially horizontal within and/or adjacent to the thin hydrocarbon layer or thin hydrocarbon layers.
- a relatively thin hydrocarbon layer may be at a substantial depth below a ground surface.
- a formation may have an overburden of up to about 650 m in depth. The cost of drilling a large number of substantially vertical wells within a formation to a significant depth may be expensive. It may be advantageous to place heaters horizontally within these formations to heat large portions of the formation for lengths up to about 1600 m. Using horizontal heaters may reduce the number of vertical wells that are needed to place a sufficient number of heaters within the formation.
- FIG. 8 illustrates an embodiment of hydrocarbon containing layer 124 that may be at a near-horizontal angle with respect to an upper surface of ground 148.
- An angle of hydrocarbon containing layer 124 may vary.
- hydrocarbon containing layer 124 may dip or be steeply dipping. Economically viable production of a steeply dipping hydrocarbon containing layer may not be possible using presently available mining methods.
- a wellbore may be formed using a drill equipped with a steerable motor and an accelerometer.
- the steerable motor and accelerometer may allow the wellbore to follow a layer in the hydrocarbon containing formation.
- a steerable motor may maintain a substantially constant distance between heater well 130 and a boundary of hydrocarbon containing layer 124 throughout drilling of the opening.
- geosteered drilling may be used to drill a wellbore in a hydrocarbon containing formation.
- Geosteered drilling may include determining or estimating a distance from an edge of hydrocarbon containing layer 124 to the wellbore with a sensor.
- the sensor may monitor variations in characteristics or signals in the formation. The characteristic or signal variance may allow for determination of a desired drill path.
- the sensor may monitor resistance, acoustic signals, magnetic signals, gamma rays, and/or other signals within the formation.
- a drilling apparatus for geosteered drilling may include a steerable motor. The steerable motor may be controlled to maintain a predetermined distance from an edge of a hydrocarbon containing layer based on data collected by the sensor.
- wellbores may be formed in a formation using other techniques.
- Wellbores may be formed by impaction techniques and/or by sonic drilling techniques.
- the method used to form wellbores may be determined based on a number of factors. The factors may include, but are not limited to, accessibility of the site, depth of the wellbore, properties of the overburden, and properties of the hydrocarbon containing layer or layers.
- FIG. 9 illustrates an embodiment of a plurality of heater wells 130 formed in hydrocarbon layer 124.
- Hydrocarbon layer 124 may be a steeply dipping layer.
- One or more of heater wells 130 may be formed in the formation such that two or more of the heater wells are substantially parallel to each other, and/or such that at least one heater well is substantially parallel to a boundary of hydrocarbon layer 124.
- one or more of heater wells 130 may be formed in hydrocarbon layer 124 by a magnetic steering method. Examples of magnetic steering methods are illustrated in U.S. Patent Nos.
- Magnetic steering may include drilling heater well 130 parallel to an adjacent heater well.
- the adjacent well may have been previously drilled.
- Magnetic steering may include directing drilling by sensing and/or determining a magnetic field produced in an adjacent heater well.
- the magnetic field may be produced in the adjacent heater well by flowing a current through an insulated current-carrying wireline disposed in the adjacent heater well.
- Magnetic steering is the use of rotating magnet ranging to monitor the distance between wellbores.
- Vector Magnetics LLC (Ithaca, NY) uses one example of a rotating magnet ranging system.
- rotating magnet ranging a magnet rotates with the drill bit in one wellbore to generate a magnetic field.
- a magnetometer in another wellbore is used to sense the magnetic field produced by the rotating magnet.
- Data from the magnetometer can be used to measure the coordinates (x, y, and z) of the drill bit in relation to the magnetometer.
- magnetostatic steering may be used to form openings adjacent to a first opening.
- U.S. Patent No. 5,541,517 issued to Hartmann et al. describes a method for drilling a wellbore relative to a second wellbore that has magnetized casing portions.
- a magnet or magnets When drilling a wellbore (opening), a magnet or magnets may be inserted into a first opening to provide a magnetic field used to guide a drilling mechanism that forms an adjacent opening or adjacent openings.
- the magnetic field may be detected by a 3-axis fluxgate magnetometer in the opening being drilled.
- a control system may use information detected by the magnetometer to determine and implement operation parameters needed to form an opening that is a selected distance away (e.g., parallel) from the first opening (within desired tolerances).
- wellbores formed by magnetic tracking may be used for in situ conversion processes (i.e., heat source wellbores, production wellbores, injection wellbores, etc.), for steam assisted gravity drainage processes, the formation of perimeter barriers or frozen barriers (i.e., barrier wells or freeze wells), and/or for soil remediation processes.
- magnetic tracking may be used to form wellbores for processes that require relatively small tolerances or variations in distances between adjacent wellbores.
- freeze wells may need to be positioned parallel to each other with relatively little or no variance in parallel alignment to allow for formation of a continuous frozen barrier around a treatment area.
- a magnetic string may be placed in a vertical well (e.g., a vertical observation well).
- the magnetic string in the vertical well may be used to guide the drilling of a horizontal well such that the horizontal well passes the vertical well at a selected distance relative to the vertical well and/or at a selected depth in the formation.
- Bessel equations may be used to determine the spacing between adjacent wellbores using measurements of magnetic field strengths.
- the magnetic field from a first wellbore may be measured by a magnetometer in a second wellbore.
- Analysis of the magnetic field strengths using derivations of Bessel equations may determine the coordinates of the second wellbore relative to the first wellbore.
- the magnetic potential at position (r, z) is given by:
- ⁇ (r,z) ⁇ - ⁇ (-l)" ⁇ r 2 +(z-nLI2) 2 ⁇ ⁇ .
- EQN.1 can be written in the form:
- EQNS.7 and 8 suggest the limit of D 6 [0,1/2].
- g can be expressed in terms of hyperbolic and trigonometric functions.
- a simple special case is:
- EQN.12 therefore may be generalized to:
- ⁇ (r,z) — ⁇ K 0 ⁇ (2m + l)2 ⁇ r / L ⁇ cos ⁇ (2m + l)2 ⁇ z / L ⁇ .
- B z — ⁇ (2m + l)K 0 ⁇ (2m + l)2 ⁇ r lL ⁇ s ⁇ (2m + l)2 ⁇ zl L ⁇ .
- Bessel functions have the following asymptotic form:
- EQNS. 20 and 21 may be approximated by:
- the magnetic field strengths B r and B z may be used to estimate the position of the second wellbore relative to the first wellbore by solving EQNS. 23 and 24 for r and z.
- the magnets may be moved (e.g., by moving a magnetic string) with the magnetometer sensors stationary and multiple measurements may be taken to remove fixed magnetic fields (e.g., earth's magnetic field, other wells, other equipment, etc.) from affecting the measurement of the relative position of the wellbores.
- three measurements may be used to eliminate the effects of fixed magnetic fields.
- a first measurement may be taken at a first location.
- a second measurement may be taken at a second location LI from the first location.
- a third measurement may be taken at a third location L/2 from the first location. At least two of the measurements (e.g., the first and third measurements) may be averaged to remove fixed magnetic field effects.
- Use of all three measurements may determine the azimuthal angle between the wellbores, the radial distance between wellbores, and the initial distance along the z-axis of the first measurement location.
- FIGS. 10, 11, and 12 show the magnetic field components as a function of hole depth of neighboring observation wellbores.
- B 2 is the magnetic field component parallel to the lengths of the wellbores
- B r is the magnetic field component in a perpendicular direction between the wellbores
- B Hsr is the angular magnetic field component between the wellbores.
- B Hsr is zero because there was no angular offset between the two wellbores.
- FIG. 10 shows the magnetic field components with a horizontal wellbore at 100 m depth and a neighboring observation wellbore at 90 m depth (i.e., 10 m wellbore spacing).
- the poles had a magnetic field strength of 1500 Gauss with a spacing, L, between the poles of 10 m.
- the poles were placed from 0 meters to 250 m along the wellbore with a positive pole at 80 m.
- FIG. 11 shows the magnetic field components with a horizontal wellbore at 100 m depth and a neighboring observation wellbore at 95 m depth (i.e., 5 m wellbore spacing).
- the B z component begins to flatten as the wellbore spacing decreases.
- FIGS. 10, 11, and 12 show that to be able to use the modified Bessel function solution, which is a far field approach, to monitor the magnetic field components, the spacing between poles, L, should typically be less than or about equal to the spacing between wellbores.
- FIG. 13 shows the magnetic field components with the wellbore with magnets built at 4° per every 30 m and the observation wellbore built at 4.095° per every 30 m to maintain the well spacing.
- FIG. 13 shows that the sine functions are only slightly skewed. The component maxima are no longer opposite the pole position (as shown in FIG. 10) because the wellbores are slightly offset and maintained at a constant distance.
- FIG. 14 depicts the ratio of B B HS ⁇ from FIG. 13.
- the ratio should be 5, since the observation wellbore has a separation in a perpendicular direction of 10 m from the wellbore with the magnets and an offset of 2 m (Hsr direction).
- the excessive points are due to the fact that the data for the excessive points are taken at midpoints between the poles where both B r and B Hsr are zero.
- FIG. 15 depicts the ratio of B ⁇ /B HS ⁇ with a build-up of 10° per every 30 m.
- the distance between wellbores was the same as in FIG. 14.
- FIG. 15 shows that the accuracy is still good for the high build-up rate.
- FIGS. 13-15 show that the accuracy of magnetic steering is still relatively good for build-up sections of wellbores.
- FIG. 16 depicts the B z component as a function of distance between the wellbores where a perfect fit (i.e., the difference between modeling distance and actual distance is set at zero) is set at 7 m by adjusting the pole strengths, P.
- FIG. 17 depicts the difference between the two curves in FIG. 16. As shown in FIGS. 16 and 17, the variation between the modeled and actual distance is relatively small and may be predictable.
- FIG. 18 depicts the B r component as a function of distance between the wellbores with the fit used for the perfect fit of B z set at 7 m.
- FIG. 19 depicts the difference between the two curves in FIG. 18.
- FIGS. 16-19 show that the same accuracy exists using B z or B r to determine distance.
- FIG. 20 depicts a schematic representation of an embodiment of a magnetostatic drilling operation to form an opening that is a selected distance away from (e.g., substantially parallel to) a drilled opening.
- Opening 170 may be formed in hydrocarbon layer 124.
- Opening 170 may be formed substantially horizontally within hydrocarbon layer 124.
- opening 170 may be formed substantially parallel to a boundary (e.g., the surface) of hydrocarbon layer 124.
- Opening 170 may be formed in other orientations within hydrocarbon layer 124 depending on, for example, a desired use of the opening, formation depth, a formation type, etc.
- Opening 170 may include casing 152.
- opening 170 may be an open (or uncased) wellbore.
- magnetic string 154 may be inserted into opening 170. Magnetic string 154 may be unwound from a reel into opening 170. In an embodiment, magnetic string 154 includes one or more magnet segments 156.
- casing 152 may be a conduit. Casing 152 may be made of a material that is not significantly influenced by a magnetic field (e.g., non-magnetic alloy such as non-magnetic stainless steel (e.g., 304, 310, 316 stainless steel), reinforced polymer pipe, or brass tubing). The casing may be a conduit of a conductor-in-conduit heater, or it may be perforated liner or casing.
- the casing may be made of a material that is influenced by a magnetic field (e.g., carbon steel).
- a material that is influenced by a magnetic field may weaken the strength of the magnetic field to be detected by drilling apparatus 164 in adjacent opening 166.
- carbon steel may weaken the magnetic field strength outside of the casing (e.g., by a factor of 3 depending on the diameter, wall thickness, and or magnetic permeability of the casing).
- Measurements may be made with the magnetic string inside the carbon steel casing (or other magnetically shielding casing) at the surface to determine the effective pole strengths of the magnetic string when shielded by the carbon steel casing.
- casing 152 may not be used (e.g., for an open wellbore).
- Measurements of the magnetic field produced by magnetic string 154 in adjacent opening 166 may be used to determine the relative coordinates of adjacent opening 166 to opening 170.
- drilling apparatus 164 may include a magnetic guidance sensor probe.
- the magnetic guidance sensor probe may contain a 3-axis fluxgate magnetometer and a 3-axis inclinometer.
- the inclinometer is typically used to determine the rotation of the sensor probe relative to the earth's gravitational field (i.e., the "toolface angle").
- a general magnetic guidance sensor probe may be obtained from Tensor Energy Products (Round Rock, TX).
- the magnetic guidance sensor probe may be located inside the drilling string of a river crossing rig.
- River crossing rigs may be used to drill horizontal wellbores or substantially horizontal wellbores through a hydrocarbon layer.
- river crossing rigs are used to drill angled wellbores through an overburden of a formation with a substantially horizontal wellbore within the hydrocarbon layer.
- the river crossing rig may form a wellbore with a first opening at a first position on the surface and a second opening at a second position on the surface at the other end of the wellbore.
- a river crossing rig may include machinery at sites selected for the first and second openings.
- Machinery e.g., at the site of the first opening
- the same machinery or other machinery e.g., at the site of the second opening
- equipment e.g., heat sources, production conduits, etc.
- Drilling entry angles for river crossing rigs may vary between about 5° and about 20° with a typical angle of about 10° or about 12°.
- the wellbore is drilled at the entry angle until a specified depth is reached (generally at some location within the hydrocarbon layer of the formation), at which depth the drilling string is turned to drill in a substantially horizontally direction through the formation.
- the substantially horizontal section of the wellbore is drilled until the wellbore reaches a predetermined horizontal length. After the predetermined horizontal length is reached, the drilling string is turned to an exit angle, which is typically, but not necessarily, the same as the entry angle, to meet with machinery at the second end of the wellbore.
- Magnet segments 156 may be placed within conduit 158.
- Conduit 158 may be a threaded or seamless coiled tubular.
- Conduit 158 may be formed by coupling one or more sections 162.
- Sections 162 may include nonmagnetic materials such as, but not limited to, stainless steel.
- conduit 158 is formed by coupling several threaded tubular sections.
- Sections 162 may have any length desired (e.g., the sections may have a standard length for threaded tubulars). Sections 162 may have a length chosen to produce magnetic fields with selected distances between junctions of opposing poles in magnetic string 154.
- the distance between junctions of opposing poles may determine the sensitivity of a magnetic steering method (i.e., the accuracy in determining the distance between adjacent wellbores).
- the distance between junctions of opposing poles is chosen to be on the same scale as the distance between adjacent wellbores (e.g., the distance between junctions may in a range of about 1 m to about 500 m or, in some cases, in a range of about 1 m to about 200 m).
- conduit 158 is a threaded stainless steel tubular (e.g., a Schedule 40, 304 stainless steel tubular with an outside diameter of about 7.3 cm (2.875 in.) formed from approximately 6 m (20 ft.) long sections 162).
- Conduit 158 may have a length between about 125 m and about 175 m. Other lengths of conduit 158 (e.g., less than about 125 m or greater than 175 m) may be used depending on a desired application of the magnetic string.
- sections 162 of conduit 158 may include two magnet segments 156. More or less than two segments may also be used in sections 162. Magnet segments 156 may be arranged within sections 162 such that adjacent magnet segments have opposing polarities (i.e., the segments are repelled by each other due to opposing poles (e.g., N-N) at the junction of the segments), as shown in FIG. 20.
- one section 162 includes two magnet segments 156 of opposing polarities. The polarity between adjacent sections 162 may be arranged such that the sections have attracting polarities (i.e., the sections are attracted to each other due to attracting poles (e.g., S-N) at the junction of the sections), as shown in FIG. 20.
- Arranging the opposing poles approximate the center of each section may make assembly of the magnet segments within each section relatively easy.
- the approximate centers of adjacent sections 162 have opposite poles.
- the approximate center of one section may have north poles and the adjacent section (or sections on each end of the one section) may have south poles as shown in FIG. 20.
- Fasteners 160 may be placed at the ends of sections 162 to hold magnet segments 156 within the sections.
- Fasteners 160 may include, but are not limited to, pins, bolts, or screws.
- Fasteners 160 may be made of nonmagnetic materials.
- ends of sections 162 may be closed off (e.g., end caps placed on the ends) to enclose magnet segments 156 within the sections.
- fasteners 160 may also be placed at junctions of opposing poles of adjacent magnet segments 156 to inhibit the adjacent segments from moving apart.
- FIG. 21 depicts an embodiment of section 162 with two magnet segments 156 with opposing poles.
- Magnet segments 156 may include one or more magnets 168 coupled to form a single magnet segment.
- Magnets 168 may be Alnico magnets or other types of magnets with sufficient magnetic strength to produce a magnetic field that can be sensed in a nearby wellbore. Alnico magnets are made primarily from alloys of aluminum, nickel and cobalt and may be obtained, for example, from Adams Magnetic Products, Co. (Elmhurst, IL). In an embodiment, magnets 168 are Alnico magnets about 6 cm in diameter and about 15 cm in length. Assembling a magnet segment from several individual magnets increases the strength of the magnetic field produced by the magnet segment.
- the pole strength of a magnet segment may be between about 1000 Gauss and about 2000 Gauss (e.g., about 1500 Gauss).
- Magnets 168 may be coupled with attracting poles coupled such that magnet segment 156 is formed with a south pole at one end and a north pole at a second end.
- 40 magnets 168 of about 15 cm in length are coupled to form magnet segment 156 of about 6 m in length.
- Opposing poles of magnet segments 156 may be aligned proximate the center of section 162 as shown in FIGS. 20 and 21. Magnet segments may be placed within section 162 and held within the section with fasteners 160.
- One or more sections 162 may be coupled as shown in FIG. 20, to form a magnetic string.
- FIG. 22 depicts a schematic of an embodiment of a portion of magnetic string 154.
- Magnet segments 156 may be positioned such that adjacent segments have opposing poles. In some embodiments, force may be applied to minimize distance 172 between magnet segments 156. Additional segments may be added to increase a length of magnetic string 154. In certain embodiments, magnet segments 156 may be located within sections 162, as shown in FIG. 20. Magnetic strings may be coiled after assembling. Installation of the magnetic string may include uncoiling the magnetic string. Coiling and uncoiling of the magnetic string may also be used to change position of the magnetic string relative to a sensor in a nearby wellbore (e.g., drilling apparatus 164 in opening 166 as shown in FIG. 20).
- a nearby wellbore e.g., drilling apparatus 164 in opening 166 as shown in FIG. 20.
- Magnetic strings may include multiple south-south and north-north opposing pole junctions. As shown in FIG. 22, the multiple opposing pole junctions may induce a series of magnetic fields 174. Alternating the polarity of portions within a magnetic string may provide several magnetic field differentials. The magnetic field differentials may allow for control of the desired spacing between drilled wellbores. Increasing the distance between opposing pole junctions within the magnetic string may increase the radial distance at which a magnetometer may detect a magnetic field. In some embodiments, the distance between opposing pole junctions within the magnetic string may be varied. For example, more magnets may be used in portions proximate the earth's surface than in portions positioned deeper in the formation.
- the distance between junctions of opposing poles of the magnetic strings may be increased or decreased when the separation distance between two wellbores increases or decreases, respectively. Shorter distances between junctions of opposing poles increases the frequency of variations in the magnetic field, which may provide more guidance to the drilling operation for smaller wellbore separation distances. Longer distances between junctions of opposing poles may be used to increase the overall magnetic field strength for larger wellbore separation distances. For example, a distance between junctions of opposing poles of about 6 m may induce a magnetic field sufficient to allow drilling of adjacent wellbores at distances of less than about 16 m. In certain embodiments, the spacing between junctions of opposing poles may be varied between about 3 m and about 24 m.
- the spacing between junctions of opposing poles may be varied between about 0.6 m and about 60 m.
- the spacing between junctions of opposing poles may be varied to adjust the sensitivity of the drilling system (e.g., the allowed tolerance in spacing between adjacent wellbores).
- the strength of the magnets used may affect the strength of the magnetic field induced.
- a distance between junctions of opposing poles of about 6 m may induce a magnetic field sufficient to drill adjacent wellbores at distances of less than about 6 m.
- a distance between junctions of opposing poles of about 6 m may induce a magnetic field sufficient to drill adjacent wellbores at distances of less than about 10 m.
- a length of the magnetic string may be based on an economic balance between cost of the string and the cost of having to reposition the string during drilling.
- a string length may range from about 30 m to about 500 m.
- a magnetic string may have a length of about 150 m.
- the magnetic string may need to be repositioned if the openings being drilled are longer than the length of the string.
- the center wellbore When multiple wellbores are to be drilled around a center wellbore, the center wellbore may be drilled and magnetic strings may be placed in the center wellbore to guide the drilling of the other wellbores substantially surrounding the center wellbore. Cumulative errors in drilling may be limited by drilling neighboring wellbores guided by the magnetic string. Additionally, only wellbores using the magnetic string may include a nonmagnetic liner, which may be more expensive than typical liners.
- a first wellbore may be formed at the center of the well pattern.
- a magnetic string may be placed in the first wellbore.
- the neighboring (or surrounding) six wellbores may be formed using the magnetic string in the first wellbore for guidance.
- additional wellbores may be formed by placing the magnetic string in one of the six surrounding wellbores and forming the nearest neighboring wellbores to the wellbore with the magnetic string.
- the process of forming nearest neighboring wellbores and moving the magnetic string to form successive neighboring wellbores may be repeated until a wellbore pattern has been formed for a hydrocarbon containing formation. Drilling as many nearest neighbor wellbores as possible from a single wellbore may reduce the cost and time associated with moving the magnetic string from wellbore to wellbore and/or installing multiple magnetic strings.
- the nearest neighboring wellbores to a previously formed wellbore are formed using magnetic steering with a magnetic string placed in the previously formed wellbore.
- the previously formed wellbore may have been formed by any standard drilling method (e.g., gyroscope, inclinometer, earth's field magnetometer, etc.) or by magnetic steering from another previously formed wellbore.
- Forming nearest neighbor wellbores with magnetic steering may reduce the overall deviation between wellbores in a well pattern formed for a hydrocarbon containing formation. For example, the deviation between wellbores may be kept below about ⁇ 1 m for every 500 m drilled.
- heat may be varied along the lengths of wellbores to compensate for any variations in spacing between heater wellbores.
- one or more production wells 104 will typically be placed within the portion of the hydrocarbon containing formation. Formation fluids may be produced through production well 104.
- production well 104 may include a heat source. The heat source may heat the portions of the formation at or near the production well and allow for vapor phase removal of formation fluids. The need for high temperature pumping of liquids from the production well may be reduced or eliminated. Avoiding or limiting high temperature pumping of liquids may significantly decrease production costs.
- 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, and/or (3) increase formation permeability at or proximate the production well.
- an amount of heat supplied to production wells is significantly less than an amount of heat applied to heat sources that heat the formation.
- Subsurface pressure in a hydrocarbon containing formation may correspond to the fluid pressure generated within the formation.
- Heating hydrocarbons within a hydrocarbon containing formation may generate fluids by pyrolysis.
- the generated fluids may be vaporized within the formation.
- Vaporization and pyrolysis reactions may increase the pressure within the formation.
- Fluids that contribute to the increase in pressure may include, but are not limited to, fluids produced during pyrolysis and water vaporized during heating.
- a pressure within the selected section may increase as a result of increased fluid generation and vaporization of water. Controlling a rate of fluid removal from the formation may allow for control of pressure in the formation.
- pressure within a selected section of a heated portion of a hydrocarbon containing formation may vary depending on factors such as depth, distance from a heat source, a richness of the hydrocarbons within the hydrocarbon containing formation, and/or a distance from a producer well. Pressure within a formation may be determined at a number of different locations (e.g., near or at production wells, near or at heat sources, or at monitor wells).
- Heating of a hydrocarbon containing formation to a pyrolysis temperature range may occur before substantial permeability has been generated within the hydrocarbon containing formation.
- An initial lack of permeability may inhibit the transport of generated fluids from a pyrolysis zone within the formation to a production well.
- a fluid pressure within the hydrocarbon containing formation may increase proximate a heat source.
- Such an increase in fluid pressure may be caused by generation of fluids during pyrolysis of at least some hydrocarbons in the formation.
- the increased fluid pressure may be released, monitored, altered, and/or controlled through the heat source.
- the heat source may include a valve that allows for removal of some fluid from the formation.
- the heat source may include an open wellbore configuration that inhibits pressure damage to the heat source.
- pressure may be increased within a selected section of a portion of a hydrocarbon containing formation to a selected pressure during pyrolysis.
- a selected pressure may be within a range from about 2 bars absolute to about 72 bars absolute or, in some embodiments, 2 bars absolute to 36 bars absolute. Alternatively, a selected pressure may be within a range from about 2 bars absolute to about 18 bars absolute.
- a majority of hydrocarbon fluids may be produced from a formation having a pressure within a range from about 2 bars absolute to about 18 bars absolute. The pressure during pyrolysis may vary or be varied.
- the pressure may be varied to alter and/or control a composition of a formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid, and/or to control an API gravity of 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.
- increased pressure due to fluid generation may be maintained within the heated portion of the formation. Maintaining increased pressure within a formation may inhibit formation subsidence during in situ conversion. Increased formation pressure may promote generation of high quality products during pyrolysis. Increased formation pressure may facilitate vapor phase production of fluids from the formation. Vapor phase production may allow for a reduction in size of collection conduits used to transport fluids produced from the formation. Increased formation pressure may reduce or eliminate the need to compress formation fluids at the surface to transport the fluids in collection conduits to surface facilities. Maintaining increased pressure within a formation may also facilitate generation of electricity from produced non- condensable fluid. For example, the produced non-condensable fluid may be passed through a turbine to generate electricity.
- Increased pressure in the formation may also be maintained to produce more and/or improved formation fluids.
- significant amounts (e.g., a majority) of the hydrocarbon fluids produced from a formation may be non-condensable hydrocarbons.
- Pressure may be selectively increased and/or maintained within the formation to promote formation of smaller chain hydrocarbons in the formation.
- Producing small chain hydrocarbons in the formation may allow more non-condensable hydrocarbons to be produced from the formation.
- the condensable hydrocarbons produced from the formation at higher pressure may be of a higher quality (e.g., higher API gravity) than condensable hydrocarbons produced from the formation at a lower pressure.
- a high pressure may be maintained within a heated portion of a hydrocarbon containing formation to inhibit production of formation fluids having carbon numbers greater than, for example, about 25.
- Some high carbon number compounds may be entrained in vapor in the formation and may be removed from the formation with the vapor.
- a high pressure in the formation may inhibit entrainment of high carbon number compounds and/or multi-ring hydrocarbon compounds in the vapor.
- Increasing pressure within the hydrocarbon containing formation may increase a boiling point of a fluid within the portion.
- 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.
- Maintaining increased pressure within a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality. Maintaining increased pressure may promote vapor phase transport of pyrolyzation fluids within the formation. Increasing the pressure often permits production of lower molecular weight hydrocarbons since such lower molecular weight hydrocarbons will more readily transport in the vapor phase in the formation.
- Generation of lower molecular weight hydrocarbons is believed to be due, in part, to autogenous generation and reaction of hydrogen within a portion of the hydrocarbon containing formation.
- maintaining an increased pressure may force hydrogen generated during pyrolysis into a liquid phase (e.g., by dissolving).
- Heating the portion to a temperature within a pyrolysis temperature range may pyrolyze hydrocarbons within the formation to generate pyrolyzation fluids in a liquid phase.
- the generated components may include double bonds and/or radicals.
- 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 in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation. Shorter chain hydrocarbons may enter the vapor phase and may be produced from the formation.
- Vapor phase production may permit increased recovery of lighter (and relatively high quality) pyrolyzation fluids. Vapor phase production may result in less formation fluid being left in the formation after the fluid is produced by pyrolysis. Vapor phase production may allow for fewer production wells in the formation than are present using liquid phase or liquid/vapor phase production. Fewer production wells may significantly reduce equipment costs associated with an in situ conversion process.
- a portion of a hydrocarbon containing formation may be heated to increase a partial pressure of H 2 .
- an increased H 2 partial pressure may include H 2 partial pressures in a range from about 0.5 bars to about 7 bars.
- an increased H 2 partial pressure range may include H 2 partial pressures in a range from about 5 bars to about 7 bars.
- a majority of hydrocarbon fluids may be produced wherein a H 2 partial pressure is within a range of about 5 bars to about 7 bars.
- a range of H 2 partial pressures within the pyrolysis H 2 partial pressure range may vary depending on, for example, temperature and pressure of the heated portion of the formation.
- the H 2 may be available to react with pyrolyzed components of the hydrocarbons. Reaction of H 2 with the pyrolyzed components of hydrocarbons may reduce polymerization of olefins into tars and other cross-linked, difficult to upgrade, products. Therefore, production of hydrocarbon fluids having low API gravity values may be inhibited.
- Controlling pressure and temperature within a hydrocarbon containing formation may allow properties of the produced formation fluids to be controlled.
- composition and quality of formation fluids produced from the formation may be altered by altering an average pressure and/or an average temperature in a selected section of a heated portion of the formation.
- the quality of the produced fluids may be evaluated based on characteristics of the fluid such as, but not limited to, API gravity, percent olefins in the produced formation fluids, ethene to ethane ratio, atomic hydrogen to carbon ratio, percent of hydrocarbons within produced formation fluids having carbon numbers greater than 25, total equivalent production (gas and liquid), total liquids production, and/or liquid yield as a percent of Fischer Assay.
Abstract
Description
Claims
Priority Applications (3)
Application Number | Priority Date | Filing Date | Title |
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CA 2462805 CA2462805C (en) | 2001-10-24 | 2002-10-24 | Forming openings in a hydrocarbon containing formation using magnetic tracking |
AU2002342139A AU2002342139A1 (en) | 2001-10-24 | 2002-10-24 | Forming openings in a hydrocarbon containing formation using magnetic tracking |
CN028211057A CN1575377B (en) | 2001-10-24 | 2002-10-24 | Method and system for forming holes in stratum, holes formed by the method and system, and compound generated thereby |
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PCT/US2002/034203 WO2003036032A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation to produce heated fluids |
PCT/US2002/034210 WO2003035811A1 (en) | 2001-10-24 | 2002-10-24 | Remediation of a hydrocarbon containing formation |
PCT/US2002/034274 WO2003036041A2 (en) | 2001-10-24 | 2002-10-24 | In situ recovery from a hydrocarbon containing formation using barriers |
PCT/US2002/034198 WO2003036030A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing and upgrading of produced hydrocarbons |
PCT/US2002/034263 WO2003036035A2 (en) | 2001-10-24 | 2002-10-24 | In situ upgrading of coal |
PCT/US2002/034209 WO2003036034A1 (en) | 2001-10-24 | 2002-10-24 | Coductor-in-conduit heat sources with an electrically conductive material in the overburden |
PCT/US2002/034023 WO2003040513A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation |
PCT/US2002/034264 WO2003035801A2 (en) | 2001-10-24 | 2002-10-24 | Producing hydrocarbons and non-hydrocarbon containing materials from a hydrocarbon containing formation |
PCT/US2002/034207 WO2003036033A1 (en) | 2001-10-24 | 2002-10-24 | Simulation of in situ recovery from a hydrocarbon containing formation |
PCT/US2002/034212 WO2003036024A2 (en) | 2001-10-24 | 2002-10-24 | Method and system for in situ heating a hydrocarbon containing formation by a u-shaped opening |
PCT/US2002/034265 WO2003036036A1 (en) | 2001-10-24 | 2002-10-24 | In situ recovery from lean and rich zones in a hydrocarbon containing formation |
PCT/US2002/034201 WO2003036031A2 (en) | 2001-10-24 | 2002-10-24 | Seismic monitoring of in situ conversion in a hydrocarbon containing formation |
PCT/US2002/034533 WO2003036038A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation via backproducing through a heater well |
PCT/US2002/034266 WO2003036040A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation using a natural distributed combustor |
PCT/US2002/034272 WO2003036043A2 (en) | 2001-10-24 | 2002-10-24 | Forming openings in a hydrocarbon containing formation using magnetic tracking |
PCT/US2002/034384 WO2003036037A2 (en) | 2001-10-24 | 2002-10-24 | Installation and use of removable heaters in a hydrocarbon containing formation |
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PCT/US2002/034536 WO2003036039A1 (en) | 2001-10-24 | 2002-10-24 | In situ production of a blending agent from a hydrocarbon containing formation |
PCT/US2002/034203 WO2003036032A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation to produce heated fluids |
PCT/US2002/034210 WO2003035811A1 (en) | 2001-10-24 | 2002-10-24 | Remediation of a hydrocarbon containing formation |
PCT/US2002/034274 WO2003036041A2 (en) | 2001-10-24 | 2002-10-24 | In situ recovery from a hydrocarbon containing formation using barriers |
PCT/US2002/034198 WO2003036030A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing and upgrading of produced hydrocarbons |
PCT/US2002/034263 WO2003036035A2 (en) | 2001-10-24 | 2002-10-24 | In situ upgrading of coal |
PCT/US2002/034209 WO2003036034A1 (en) | 2001-10-24 | 2002-10-24 | Coductor-in-conduit heat sources with an electrically conductive material in the overburden |
PCT/US2002/034023 WO2003040513A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation |
PCT/US2002/034264 WO2003035801A2 (en) | 2001-10-24 | 2002-10-24 | Producing hydrocarbons and non-hydrocarbon containing materials from a hydrocarbon containing formation |
PCT/US2002/034207 WO2003036033A1 (en) | 2001-10-24 | 2002-10-24 | Simulation of in situ recovery from a hydrocarbon containing formation |
PCT/US2002/034212 WO2003036024A2 (en) | 2001-10-24 | 2002-10-24 | Method and system for in situ heating a hydrocarbon containing formation by a u-shaped opening |
PCT/US2002/034265 WO2003036036A1 (en) | 2001-10-24 | 2002-10-24 | In situ recovery from lean and rich zones in a hydrocarbon containing formation |
PCT/US2002/034201 WO2003036031A2 (en) | 2001-10-24 | 2002-10-24 | Seismic monitoring of in situ conversion in a hydrocarbon containing formation |
PCT/US2002/034533 WO2003036038A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation via backproducing through a heater well |
PCT/US2002/034266 WO2003036040A2 (en) | 2001-10-24 | 2002-10-24 | In situ thermal processing of a hydrocarbon containing formation using a natural distributed combustor |
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