WO2014062727A1 - Procédé et appareil de gestion des gaz acides générés par pyrolyse du kérogène - Google Patents

Procédé et appareil de gestion des gaz acides générés par pyrolyse du kérogène Download PDF

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Publication number
WO2014062727A1
WO2014062727A1 PCT/US2013/065120 US2013065120W WO2014062727A1 WO 2014062727 A1 WO2014062727 A1 WO 2014062727A1 US 2013065120 W US2013065120 W US 2013065120W WO 2014062727 A1 WO2014062727 A1 WO 2014062727A1
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Prior art keywords
pyrolysis
gases
formation
kerogen
acid
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PCT/US2013/065120
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English (en)
Inventor
Scott NGUYEN
Harold Vinegar
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Genie Ip B.V.
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Priority to CA2887658A priority Critical patent/CA2887658A1/fr
Priority to US14/435,700 priority patent/US20150260024A1/en
Publication of WO2014062727A1 publication Critical patent/WO2014062727A1/fr
Priority to IL238259A priority patent/IL238259A0/en
Priority to MA38097A priority patent/MA38097B1/fr

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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
    • E21B43/243—Combustion in situ
    • 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
    • C10G1/00—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal
    • C10G1/02—Production of liquid hydrocarbon mixtures from oil-shale, oil-sand, or non-melting solid carbonaceous or similar materials, e.g. wood, coal by distillation
    • 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
    • C10G7/00—Distillation of hydrocarbon oils
    • C10G7/12—Controlling or regulating
    • C—CHEMISTRY; METALLURGY
    • C10—PETROLEUM, GAS OR COKE INDUSTRIES; TECHNICAL GASES CONTAINING CARBON MONOXIDE; FUELS; LUBRICANTS; PEAT
    • C10K—PURIFYING OR MODIFYING THE CHEMICAL COMPOSITION OF COMBUSTIBLE GASES CONTAINING CARBON MONOXIDE
    • C10K1/00—Purifying combustible gases containing carbon monoxide
    • C10K1/002—Removal of contaminants
    • C10K1/003—Removal of contaminants of acid contaminants, e.g. acid gas removal
    • 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
    • E21B43/34—Arrangements for separating materials produced by the well
    • E21B43/40—Separation associated with re-injection of separated materials
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2251/00—Reactants
    • B01D2251/30—Alkali metal compounds
    • B01D2251/304—Alkali metal compounds of sodium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2251/00—Reactants
    • B01D2251/30—Alkali metal compounds
    • B01D2251/306—Alkali metal compounds of potassium
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2252/00—Absorbents, i.e. solvents and liquid materials for gas absorption
    • B01D2252/20—Organic absorbents
    • B01D2252/204—Amines
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/30—Sulfur compounds
    • B01D2257/304—Hydrogen sulfide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D2257/00—Components to be removed
    • B01D2257/50—Carbon oxides
    • B01D2257/504—Carbon dioxide
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/14—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols by absorption
    • B01D53/1456—Removing acid components
    • B—PERFORMING OPERATIONS; TRANSPORTING
    • B01—PHYSICAL OR CHEMICAL PROCESSES OR APPARATUS IN GENERAL
    • B01D—SEPARATION
    • B01D53/00—Separation of gases or vapours; Recovering vapours of volatile solvents from gases; Chemical or biological purification of waste gases, e.g. engine exhaust gases, smoke, fumes, flue gases, aerosols
    • B01D53/34—Chemical or biological purification of waste gases
    • B01D53/38—Removing components of undefined structure
    • B01D53/40—Acidic components
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/10—Feedstock materials
    • C10G2300/1033—Oil well production fluids
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/20—Characteristics of the feedstock or the products
    • C10G2300/201—Impurities
    • C10G2300/207—Acid gases, e.g. H2S, COS, SO2, HCN
    • 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
    • C10G2300/00—Aspects relating to hydrocarbon processing covered by groups C10G1/00 - C10G99/00
    • C10G2300/40—Characteristics of the process deviating from typical ways of processing
    • C10G2300/4037—In-situ processes
    • 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
    • Y02P20/00—Technologies relating to chemical industry
    • Y02P20/151—Reduction of greenhouse gas [GHG] emissions, e.g. CO2

Definitions

  • Embodiments of the invention relate to techniques for pyrolyzing sulfur-rich kerogen or bitumen (e.g. type lis kerogen), and to related methods of handling pyrolysis gases derived therefrom.
  • sulfur-rich kerogen or bitumen e.g. type lis kerogen
  • Type II kerogen known to be sulfur-rich
  • Type lis or lis A schematic representation of one type of organic matter in Type lis kerogen is illustrated below:
  • Type lis kerogen Originating from a marine-depositional environment, Type lis kerogen is rich in sulfur-bearing organic compounds, and during thermal maturation produces oil and bitumen with high sulfur content.
  • hydrocarbon fluids it is possible to produce hydrocarbon fluids by pyrolyzing Type lis kerogen either in situ or within an enclosure such as a pit or an impoundment.
  • pyrolysis of kerogen or bitumen also produces acid-gas (i.e. H 2 S and COx).
  • Embodiments of the present invention relate to methods and apparatus for pyrolysis of sulfur-rich kerogen or bitumen wherein recovery of hydrocarbon fluids via production wells or conduits is delayed in order to first recover a significant quantity of acid gases.
  • the recovery of the hydrocarbon fluids may be delayed by reducing power to heaters (i.e. at the appropriate time) used to heat the kerogen or bitumen.
  • the significant quantity of acid gases is recovered during early pyrolysis in a gas mixture containing at most low concentrations of valuable hydrogen gas and/or hydrocarbon gases.
  • H 2 S-rich and COx-rich formation gases that are generated and recovered during early pyrolysis separate from the hydrocarbon gas-rich and/or H 2 -rich pyrolysis formation gases that are recovered at a later stage of pyrolysis, it is possible to sequester (e.g. within a deep injection well) the formation gases of early pyrolysis without subjecting them to significant gas component separation and treatment before sequestration.
  • these later-stage pyrolysis formation gases may require a lesser amount of desulfurizing and other gas treatment than would be required if early-stage and later-stage pyrolysis formation gases were allowed to mix with each other.
  • smaller or fewer amine separation units and Claus plants may be required for an in situ project for unconventional oil recovery.
  • the presently disclosed teachings are applicable both to in situ pyrolysis and to pyrolysis performed within an enclosure such as a pit.
  • a pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface formation in situ so as to initiate pyrolysis of kerogen and/or bitumen therein so that a stream of pyrolysis formation gases is recovered via production wells; b. monitoring or estimating a concentration of acid gas within the gas stream; c. contingent upon an acid gas concentration being below a threshold value, subjecting pyrolysis gases of the stream to sequestration; and d. responding to an estimated or monitored increase in acid gas concentration of the gas stream by carrying at least one of: i. subjecting a greater fraction of the stream to an acid gas separation process and/or acid gas elimination process; and ii. subjecting a lesser fraction of the stream to a sequestration.
  • a pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface formation in situ so as to initiate pyrolysis of kerogen and/or bitumen therein thereby generating pyrolysis formation gases so that: i. early pyrolysis gases formed during early pyrolysis are acid-gas rich and have at most low concentrations of the combination of hydrogen gas and hydrocarbon gases; ii. a concentration of acid gases within later pyrolysis gases formed during later stages of pyrolysis is significantly less than the concentration within the early pyrolysis gases; and iii. the later pyrolysis gases are rich in hydrocarbon gases and/or hydrogen gas; b. sequestering the early pyrolysis gases; and c. subjecting the later pyrolysis gases to an acid gas separation process and/or to an acid gas elimination process.
  • a pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface formation in situ by heaters so as to initiate pyrolysis of kerogen and/or bitumen therein; b. operating the heaters so as to maximize the quantity of acid formation gases that are formed as part of a gas mixture having at most low concentrations of the combination of hydrogen gas and hydrocarbon gases; and c. sequestering the acid gases.
  • a pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface formation in situ by heaters so as to initiate pyrolysis of kerogen and/or bitumen therein; b.
  • a pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface formation in situ by heaters so as to initiate pyrolysis of kerogen and/or bitumen therein; b. monitoring or estimating content of a gas mixture stream of formation gases formed by the pyrolysis to determine an indication of an acid gas concentration thereof; and c. during an early stage of pyrolysis of the portion of the formation, operating the heater(s) at a power level determined in accordance with the acid gas concentration.
  • the heaters are subsurface heaters.
  • a pyrolysis method comprises: a. introducing hydrocarbon-containing rocks into an interior region of an enclosure to form a bed of rocks therein; b. heating the bed of rocks so as to pyrolyze kerogen or bitumen thereof so that a stream of pyrolysis formation gases is recovered via production conduit(s); c. monitoring or estimating a concentration of acid gas within the gas stream;
  • a pyrolysis method comprises a. introducing hydrocarbon-containing rocks into an interior region of an enclosure to form a bed of rocks therein; b. heating the bed of rocks so as to initiate pyrolysis of kerogen and/or bitumen therein thereby generating pyrolysis formation gases so that: i. early pyrolysis gases formed during early pyrolysis are acid-gas rich and have at most low concentrations of the combination of hydrogen gas and hydrocarbon gases; ii. a concentration of acid gases within later pyrolysis gases formed during later stages of pyrolysis is significantly less than the concentration within the early pyrolysis gases; and iii. the later pyrolysis gases are rich in hydrocarbon gases and/or hydrogen gas ; b. sequestering the early pyrolysis gases; and c. subjecting the later pyrolysis gases to an acid gas separation process and/or acid gas elimination process.
  • a pyrolysis method comprises: a. heating a hydrocarbon-containing subsurface formation in situ by heaters so as to initiate pyrolysis of kerogen and/or bitumen therein; a. introducing hydrocarbon-containing rocks into an interior region of an enclosure to form a bed of rocks therein; b. heating the bed of rocks by heaters so as to pyrolyze kerogen or bitumen thereof so as to initiate pyrolysis of kerogen and/or bitumen thereof; c. operating the heaters so as to maximize the quantity of acid formation gases that are formed as part of a gas mixture having at most low concentrations of the combination of hydrogen gas and hydrocarbon gases; and d. sequestering the acid gases.
  • a pyrolysis method comprises: a. introducing hydrocarbon-containing rocks into an interior region of an enclosure to form a bed of rocks therein; b. heating the bed of rocks by heaters so as to pyrolyze kerogen or bitumen thereof so as to initiate pyrolysis of kerogen and/or bitumen thereof; c. operating the heaters so as to maximize the quantity of acid formation gases that are formed when a bulk temperature of the pyrolyzed portion of the formation is at most 300 degrees Celsius or at most 295 degrees Celsius or at most 290 degrees Celsius; and d. sequestering the acid gases.
  • a pyrolysis method comprises: a. introducing hydrocarbon-containing rocks into an interior region of an enclosure to form a bed of rocks therein; b. heating the bed of rocks by heaters so as to pyrolyze kerogen or bitumen thereof so as to initiate pyrolysis of kerogen and/or bitumen thereof; c. monitoring or estimating content of a gas mixture stream of formation gases formed by the pyrolysis to determine an indication of an acid gas concentration thereof; and d. during an early stage of pyrolysis of the portion of the formation, operating the heater(s) at a power level determined in accordance with the acid gas concentration.
  • the interior region is maintained under anoxic conditions during the heating.
  • the enclosure is an excavated enclosure.
  • the enclosure is a pit or an impoundment.
  • the sequestration is subsurface sequestration, for example, deep well sequestration.
  • the sequestration is subsurface sequestration, for example, deep well sequestration in a well-confined saline aquifer gas cap.
  • the acid gas threshold value is between 70% and
  • the acid gas threshold value is between 70% and 95%, for example at least 85% and/or at most 90%.
  • the sequestration is carried out immediately.
  • subsurface formation is an oil shale formation or a coal formation or a bitumen formation.
  • the kerogen is type lis kerogen or the bitumen is derived from type lis kerogen.
  • the kerogen is sulfur-rich type lis kerogen or the bitumen is derived from sulfur-rich type lis kerogen.
  • the acid gas separation process is carried out in an amine unit. In some embodiments, the acid gas elimination process is carried out in a caustic system, for example, based upon sodium hydroxide or potassium hydroxide. e.
  • ratio between (i) a larger of A and B and (ii) a smaller of A and B is at most 15 or at most 10 or at most 5.
  • a 'substantial majority' refers to at least 75%. Unless specified otherwise, 'substantially all' refers to at least 90%. In some embodiments
  • substantially all' refers to at least 95% or at least 99%.
  • 'gases' e.g. hydrocarbon gases
  • non-condensable gases e.g. not condensable at STP 25 degrees C, 1 atm.
  • 'Early pyrolysis gases' are pyrolysis formation gases that are formed when a bulk temperature of the pyrolyzed portion of the formation (or of a bed of kerogen-containing or bitumen-containing rocks) is at most 300 degrees Celsius— in some embodiments, at most 295 degrees Celsius or at most 290 degrees Celsius.
  • one quantity A is less than a significantly less than a quantity B, its value is at most 30% less than that of B (i.e. A is equal to at most 0.7 B) or at most one-half of B.
  • a concentration of acid gas therein is at least 50% or at least 75% or at least 80% or at least 85% or at least 90%.
  • 'low temperature pyrolysis' is pyrolysis that occurs at temperatures of at most 290 degrees Celsius over a period of at least 3 months or at least 6 months or at least 1 year. In some embodiments, 'low temperature pyrolysis' occurs between 270 degrees Celsius and 290 degrees Celsius over this period of at least 3 months or at least 6 months or at least 1 year. In some embodiments, 'low temperature pyrolysis' occurs between 280 degrees Celsius and 290 degrees Celsius over this period of at least 3 months or at least 6 months or at least 1 year. In this temperature range, pyrolysis proceeds quickly enough to be feasible, while favoring formation of easier-to- hydrotreat species.
  • a 'boiling point' refers to an atmospheric boiling point.
  • 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 1200.
  • 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 1200 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 1200 are shown extending only along one side of heater sources 1202, but the barrier wells typically encircle all heat sources 1202 used, or to be used, to heat a treatment area of the formation.
  • Heat sources 1202 are placed in at least a portion of the formation.
  • Heat sources 1202 may include heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 1202 may also include other types of heaters. Heat sources 1202 provide heat to at least a portion of the formation to heat hydrocarbons in the formation. Energy may be supplied to heat sources 1202 through supply lines 1204. Supply lines 1204 may be structurally different depending on the type of heat source or heat sources used to heat the formation. Supply lines 1204 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. In some embodiments, 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 1206 to be spaced relatively far apart in the formation.
  • Production wells 1206 are used to remove formation fluid from the formation.
  • production well 1206 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 1206 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 1206.
  • fluid pressure in the formation may increase proximate heat sources 1202.
  • the increased fluid pressure may be released, monitored, altered, and/or controlled through one or more heat sources 1202.
  • selected heat sources 1202 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 1206 or any other pressure sink may not yet exist in the formation.
  • the fluid pressure may be allowed to increase towards a litho static pressure.
  • Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure.
  • fractures may form from heat sources 1202 to production wells 1206 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 (3 ⁇ 4) 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.
  • 3 ⁇ 4 may also neutralize radicals in the generated pyrolyzation fluids. 3 ⁇ 4 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 1206 may be transported through collection piping 1208 to treatment facilities 1210.
  • Formation fluids may also be produced from heat sources 1202. For example, fluid may be produced from heat sources 1202 to control pressure in the formation adjacent to the heat sources. Fluid produced from heat sources 1202 may be transported through tubing or piping to collection piping 1208 or the produced fluid may be transported through tubing or piping directly to treatment facilities 1210.
  • Treatment facilities 1210 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.
  • the kerogen in such kerogen or bitumen (which may be referred to as 'sulfur-rich), the kerogen can be classified into two components - 1. Parts (abbreviated as K RS ) with high concentrations of sulfur- sulfur bonds and 2. Parts (abbreviated as K LS )with low concentrations of sulfur-sulfur bonds Upon heating a target portion of the kerogen formation to pyrolysis or near- pyro lysis temperatures, the following chemical reactions may be observed:
  • bitumen analog of any feature or combination of feature(s) disclosed for the case of kerogen - for the sake of brevity, examples are only provided for the non- limiting example of kerogen.
  • FIG. 2 illustrates Arrhenius plots of both reactions - the Arrhenius plot for low-sulfur kerogen is presented as a broken line while the Arrhenius plot for high- sulfur kerogen is presented as a double line.
  • FIG. 3A is a schematic diagram of a system for in-situ thermal treatment of a hydrocarbon-containing subsurface formation 280 located below an overburden 276 and above an underburden 288.
  • a plurality of heaters 220 e.g.
  • pyrolysis may occur in stages - at lower temperatures (and during an earlier stage of pyrolysis), the formation fluids may include significant quantities of acid gases, while at higher temperatures (and during later stages of pyrolysis), the concentration of acid gases within the formation fluids may drop.
  • FIG. 3A relates to the specific non-limiting example where the hydrocarbon- containing subsurface formation 280 is a kerogen formation - in other examples, the hydrocarbon-containing subsurface formation 280 is a bitumen formation.
  • one or more production wells 224 are also deployed within the pyrolyzed target portion 284.
  • formation fluids including formation gases are recovered via production well(s) 224.
  • a gas mixture stream 296 of pyrolysis formation gases generated by pyrolysis of the target portion 284 may exit the production well(s) 224.
  • gases of the gas mixture stream 296 may flow to gas treatment facility 282.
  • Embodiments of the invention are described in the context of in- situ pyrolysis as illustrated in FIG. 3A.
  • the presently disclosed teachings are equally applicable for pyrolysis of a kerogen or bitumen of bed of hydrocarbon-containing rocks (e.g. kerogen-containing rocks) located within an enclosure— for example, an excavated enclosure such as a pit or embodiment. Examples of such pyrolysis are illustrated in FIGS. 3B-3D.
  • FIGS. 3A Various modifications of the system of FIG. 3A are illustrated in FIGS. 7- 8— the skilled artisan will appreciate that similar modifications may be made to the system of FIGS. 3B-D.
  • FIG. 4 describes the normalized cumulative production of acid gases (i.e. hydrogen sulfide and carbon dioxide) and valuable gases (i.e. hydrogen gas and hydrocarbon gases) as a function of time according to one example where subsurface heaters 220 are operated at constant and full power (see FIG. 5).
  • acid gases i.e. hydrogen sulfide and carbon dioxide
  • valuable gases i.e. hydrogen gas and hydrocarbon gases
  • Each curve has a minimum of '0' and a maximum of T and is respectively normalized by the total amount of acid gases and total amount of valuable gases that are produced from the subsurface kerogen or bitumen formation during the pyrolysis process.
  • time(Ti) refers to the time when the temperature first reaches Ti
  • iime(T 2 ) refers to the time when the temperature first reaches T 2 .
  • Ti can be about 220 or about 230 or about 240 or about 250 degrees Celsius and T 2 can be about 300 or about 290 degrees Celsius.
  • a bulk temperature of the target portion 284 of the kerogen or bitumen formation 280 is very low (i.e. less than time(T ⁇ )) and a rate of pyrolysis is insignificant.
  • the reaction rate Ri of "REACTION 1 " is significant, while the reaction rate R 2 of "REACTION 2" remains insignificant.
  • a formation gas mixture stream 296 is rich in acid gases while a concentration of H 2 - rich and hydrocarbon gas (i.e. the valuable gases) therein is relatively low.
  • the time window corresponding to the (Ti , T 2 ) temperature window is shaded in FIG. 4 - during this period of time the concentration of valuable gases within stream 296 is low, and the amount of normalized cumulative production of valuable gases from the target portion 284 of the formation 280 is also relatively small, as illustrated in FIG. 4.
  • FIG. 4 and FIG. 5 relate to the case where subsurface heaters 220 are operated at constant and full power (see the 'heater power level' curve of FIG. 5 represented as a triple line). Reference is now made to FIG. 5. Initially, for times less than time(Ti), the bulk temperature of the target portion 284 of kerogen or bitumen formation 280 increases steadily - for example, at a substantially constant rate.
  • FIG. 6 illustrates experimental data generated by pyrolyzing a sample of oil shale (i.e. a kerogeneous chalk) from the Ghareb formation in the laboratory.
  • the abscissa T[°C] is the temperature of the oil shale sample and the ordinate Q [ml/min] is the flow rate of various pyrolysis gases when the oil shale sample is heated to a particular temperature.
  • the absolute flow rate of pyrolysis formation gases Q is very small.
  • the flow rate is significantly larger and the concentration of acid gases (H 2 S and COx) within the flow of formation gases from the oil shale sample is quite significant.
  • the absolute flow rate of acid gases drops slowly, while the concentration of acid gases within the flow stream of pyrolysis formation gases drops dramatically as significant flow rates of hydrogen, hydrocarbons fluids are observed.
  • a gas detector 270 may detect a concentration of acid gases within the formation gas mixture stream 296.
  • a gas detector 270 may detect a concentration of acid gases within the formation gas mixture stream 296.
  • One manufacturer of Gas chromatography instruments is Agilent of Colorado (United States of America).
  • all gases of formation gas mixture stream 296 are directed by flow control 224 to deep injection well 260 for sequestration, and (ii) for a second period of time, for example, commencing at iime(T 2 ), all gases of formation gas mixture stream 296 are directed by flow control 224 to gas treatment facility 282.
  • all gases of formation gas mixture stream 296 are sent to gas treatment facility 282 - in this situation, 'early pyrolysis gases' of gas mixture stream 296 formed during time window TW_ T ⁇ _ T 2 and when the bulk temperature of the target portion 284 may mix with 'later pyrolysis gases' that formed after iime(T 2 ).
  • the early pyrolysis gases are H 2 S-rich and COx-rich and are characterized by at most low concentrations of H 2 and hydrocarbon gases while the concentration of H 2 S and COx within hydrocarbon-rich and H 2 -rich 'later gases' is much lower.
  • Embodiments of the present invention relate to apparatus and methods for heating hydrocarbon-containing matter (e.g. tar sands or kerogen-containing rocks such as pieces of coal or pieces of oil shale) within an enclosure such as a pit or an impoundment or a container.
  • Hydrocarbon-containing rocks are introduced into the enclosure to form a bed (e.g. a packed-bed) of rock therein.
  • Oxygen may be evacuated (e.g. under vacuum or by means of an inert sweep gas) to create a substantially oxygen-free environment within the enclosure.
  • the enclosure may be a pit, or an impoundment or a container.
  • the enclosure may be entirely below ground level, partially below and partially above, or entirely above ground level.
  • Operation of heaters in thermal communication with the hydrocarbon-containing rocks may sufficiently heat the rocks to convert kerogen or bitumen thereof into pyrolysis formation fluids comprising hydrocarbon pyrolysis fluids.
  • the formation fluids may be recovered via production conduits, or via a liquid outlet located at or near the bottom of the enclosure and/or via a vapor outlet located near the top of the enclosure, or in any other manner.
  • hydrocarbon-containing rocks examples include kerogen-containing rocks (e.g. mined oil shale or mined coal) and bitumen-containing rocks (e.g. tar sands).
  • kerogen-containing rocks e.g. mined oil shale or mined coal
  • bitumen-containing rocks e.g. tar sands
  • each of the verbs, "comprise” “include” and “have”, and conjugates thereof, are used to indicate that the object or objects of the verb are not necessarily a complete listing of members, components, elements or parts of the subject or subjects of the verb.
  • an element means one element or more than one element.

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Abstract

Dans certains modes de réalisation, cette invention concerne un procédé de pyrolyse comprenant : a. le chauffage du kérogène ou du bitume pour initier la pyrolyse de façon qu'un flux de gaz de formation de pyrolyse soit récupéré par l'intermédiaire de puits de production ou de conduits de production ; b. la surveillance ou l'estimation de la concentration de gaz acides dans le flux gazeux ; c. dans le cas où la concentration de gaz acides est au-dessous d'une valeur de seuil, la soumission des gaz de pyrolyse du flux à séquestration ; et d. la réponse à un accroissement estimé ou confirmé par surveillance de la concentration de gaz acides par la mise en œuvre d'au moins une des mesures suivantes : i. soumission d'une plus grande fraction du flux à un procédé de séparation des gaz acides et/ou à un procédé d'élimination des gaz acides ; et ii. soumission d'une plus petite fraction du flux à séquestration. L'invention ci-décrite peut être appliquée à la fois à la pyrolyse in situ et la pyrolyse mise en œuvre dans une enceinte telle qu'une fosse.
PCT/US2013/065120 2012-10-15 2013-10-15 Procédé et appareil de gestion des gaz acides générés par pyrolyse du kérogène WO2014062727A1 (fr)

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CA2887658A CA2887658A1 (fr) 2012-10-15 2013-10-15 Procede et appareil de gestion des gaz acides generes par pyrolyse du kerogene
US14/435,700 US20150260024A1 (en) 2012-10-15 2013-10-15 Method and apparatus for handling acid gases generated by pyrolysis of kerogen
IL238259A IL238259A0 (en) 2012-10-15 2015-04-13 Method and mechanism in gases produced by kerogen pyrolysis
MA38097A MA38097B1 (fr) 2012-10-15 2015-05-14 Procede et appareil de gestion des gaz acides generes par pyrolyse de kerogene

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US20110132600A1 (en) * 2003-06-24 2011-06-09 Robert D Kaminsky Optimized Well Spacing For In Situ Shale Oil Development
US20110146982A1 (en) * 2009-12-17 2011-06-23 Kaminsky Robert D Enhanced Convection For In Situ Pyrolysis of Organic-Rich Rock Formations
US20110174507A1 (en) * 2008-10-02 2011-07-21 Burnham Alan K Carbon sequestration in depleted oil shale deposits
US20110268650A1 (en) * 2010-04-30 2011-11-03 Black & Veatch Corporation Methods and apparatus for sulfur recovery from acid gases

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US20110132600A1 (en) * 2003-06-24 2011-06-09 Robert D Kaminsky Optimized Well Spacing For In Situ Shale Oil Development
US20080290719A1 (en) * 2007-05-25 2008-11-27 Kaminsky Robert D Process for producing Hydrocarbon fluids combining in situ heating, a power plant and a gas plant
US20110174507A1 (en) * 2008-10-02 2011-07-21 Burnham Alan K Carbon sequestration in depleted oil shale deposits
US20110146982A1 (en) * 2009-12-17 2011-06-23 Kaminsky Robert D Enhanced Convection For In Situ Pyrolysis of Organic-Rich Rock Formations
US20110268650A1 (en) * 2010-04-30 2011-11-03 Black & Veatch Corporation Methods and apparatus for sulfur recovery from acid gases

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US20150260024A1 (en) 2015-09-17

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