US20150260024A1

US20150260024A1 - Method and apparatus for handling acid gases generated by pyrolysis of kerogen

Info

Publication number: US20150260024A1
Application number: US14/435,700
Authority: US
Inventors: Scott Nguyen; Harold Vinegar
Original assignee: GENIE AP BV
Current assignee: GENIE AP BV
Priority date: 2012-10-15
Filing date: 2013-10-15
Publication date: 2015-09-17
Also published as: MA38097A1; IL238259A0; MA38097B1; CA2887658A1; WO2014062727A1

Abstract

In some embodiments, a pyrolysis method comprises: a. heating kerogen or bitumen to initiate pyrolysis so that a stream of pyrolysis formation gases is recovered via production wells or production conduits; 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 performing 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. The presently disclosed teachings are applicable both to in situ pyrolysis and to pyrolysis performed within an enclosure such as a pit.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application claims priority to U.S. Provisional Application No. 61/714,220 filed on Oct. 15, 2012, which is incorporated by reference herein in its entirety.

FIELD OF THE INVENTION

Embodiments of the invention relate to techniques for pyrolyzing sulfur-rich kerogen or bitumen (e.g. type IIs kerogen), and to related methods of handling pyrolysis gases derived therefrom.

BACKGROUND

The world's supply of conventional sweet, light crude oil is declining, and discoveries and access to new resources for this premium oil are becoming more challenging. To supplement this decline and to meet the rising global demand, oils of increasing sulfur content are being produced and brought to market. Sources of sulfur-rich oil may be found in Canada, Venezuela, the United States (California), Mexico and the Middle East.
Many sulfur-rich hydrocarbons are sourced from a subset of Type II kerogen known to be sulfur-rich, called Type IIs or IIs. A schematic representation of one type of organic matter in Type IIs kerogen is illustrated below:
Originating from a marine-depositional environment, Type IIs kerogen is rich in sulfur-bearing organic compounds, and during thermal maturation produces oil and bitumen with high sulfur content.
It is possible to produce hydrocarbon fluids by pyrolyzing Type IIs kerogen either in situ or within an enclosure such as a pit or an impoundment. Unfortunately, in addition to valuable fluids (i.e. hydrocarbon fluids and hydrogen gas), pyrolysis of kerogen or bitumen also produces acid-gas (i.e. H₂S and CO_X).
There is an ongoing need for economically-viable and environmentally-friendly techniques for disposing of acid-gas derived from Type IIs kerogen.

SUMMARY OF EMBODIMENTS

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.
By keeping the H₂S-rich and CO_X-rich formation gases that are generated and recovered during early pyrolysis separate from the hydrocarbon gas-rich and/or H₂-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.
Because the H₂S-rich and CO_X-rich early-stage pyrolysis formation gases are not mixed together with the later-stage pyrolysis formation gases (i.e. that have relatively high concentrations of H₂and/or hydrocarbon gas rich), 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. On a practical level, 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. 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 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. 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.
In some embodiments, 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;
d. 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. 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.
In some embodiments, the interior region is maintained under anoxic conditions during the heating.
In some embodiments, the enclosure is an excavated enclosure.
In some embodiments, the enclosure is a pit or an impoundment.
In some embodiments, the sequestration is subsurface sequestration, for example, deep well sequestration.
In some embodiments, the sequestration is subsurface sequestration, for example, deep well sequestration in a well-confined saline aquifer gas cap.
In some embodiments, the acid gas threshold value is between 70% and 95%.
In some embodiments, the acid gas threshold value is between 70% and 95%, for example at least 85% and/or at most 90%.
In some embodiments, the sequestration is carried out immediately.
In some embodiments, the sequestration is carried out at a much later time.
In some embodiments, subsurface formation is an oil shale formation or a coal formation or a bitumen formation.
In some embodiments, the kerogen is type IIs kerogen or the bitumen is derived from type IIs kerogen.
In some embodiments, the kerogen is sulfur-rich type IIs kerogen or the bitumen is derived from sulfur-rich type IIs kerogen.
In some embodiments, 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.

DETAILED DESCRIPTION OF EMBODIMENTS

The invention is herein described, by way of example only, with reference to the accompanying drawings. With specific reference now to the drawings in detail, it is stressed that the particulars shown are by way of example and for purposes of illustrative discussion of the preferred embodiments of the exemplary system only and are presented in the cause of providing what is believed to be a useful and readily understood description of the principles and conceptual aspects of the invention. In this regard, no attempt is made to show structural details of the invention in more detail than is necessary for a fundamental understanding of the invention, the description taken with the drawings making apparent to those skilled in the art how several forms of the invention may be embodied in practice and how to make and use the embodiments.
For brevity, some explicit combinations of various features are not explicitly illustrated in the figures and/or described. It is now disclosed that any combination of the method or device features disclosed herein can be combined in any manner—including any combination of features—and any combination of features can be included in any embodiment and/or omitted from any embodiments.

DEFINITIONS

For convenience, in the context of the description herein, various terms are presented here. To the extent that definitions are provided, explicitly or implicitly, here or elsewhere in this application, such definitions are understood to be consistent with the usage of the defined terms by those of skill in the pertinent art(s). Furthermore, such definitions are to be construed in the broadest possible sense consistent with such usage.
If two numbers A and B are “on the same order of magnitude”, then 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.
Unless specified otherwise, 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%.
For the present disclosure, ‘gases’ (e.g. hydrocarbon gases) refer to non-condensable gases—i.e. 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.
When 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.
When formation gases are ‘acid-gas rich’ then 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%.
When formation gases have ‘at most low concentrations of the combination of hydrogen gas and hydrocarbon gases’ then the sum of (i) a concentration of hydrocarbon gas; and (ii) a concentration of all non-condensable hydrocarbon gases is at most 20% or at most 15% or at most 10% or at most 5%.
For the present disclosure, ‘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.
For the present disclosure, unless otherwise noted, a ‘boiling point’ refers to an atmospheric boiling point.
For the present disclosure, sulfur-rich type IIs kerogen is at least 6% wt/wt or at least 7% wt/wt or at least 8% wt/wt sulfur.
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. In some embodiments, 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. In the embodiment depicted in FIG. 1, 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.
When the formation is heated, 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. In some embodiments, 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. In some in situ heat treatment process embodiments, 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. In some embodiments, 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.
In some embodiments, 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 (C₆hydrocarbons 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.
In some hydrocarbon containing formations, production of hydrocarbons from the formation is inhibited until at least some hydrocarbons in the formation have been mobilized and/or pyrolyzed. Formation fluid may be produced from the formation when the formation fluid is of a selected quality. In some embodiments, 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.
In some hydrocarbon containing formations, 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. During initial heating, 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. For example, selected heat sources 1202 or separate pressure relief wells may include pressure relief valves that allow for removal of some fluid from the formation.
In some embodiments, 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. For example, 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.
After mobilization and/or pyrolysis temperatures are reached and production from the formation is allowed, 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.
In some in situ heat treatment process embodiments, 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. For example, 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 (H₂) 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. In addition, H₂may also neutralize radicals in the generated pyrolyzation fluids. H₂in 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. In some embodiments, 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. In some embodiments, electricity may be generated using the heat of the fluid produced from the formation. Also, 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. For example, 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. In some embodiments, the working fluid for the cycle used to generate electricity is aqua ammonia.
Some embodiments of the present invention relate to type IIs kerogen (e.g. sulfur-rich) or bitumen derivatives thereof. Not wishing to be bound by theory, 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_II-S) with high concentrations of sulfur-sulfur bonds and 2. Parts (abbreviated as K_L-S) with low concentrations of sulfur-sulfur bonds
Upon heating a target portion of the kerogen formation to pyrolysis or near-pyrolysis temperatures, the following chemical reactions may be observed:
It is appreciated that there are analogous reactions for the case of bitumen formations—for the present disclosure, there is a 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.
One salient feature of sulfur-rich subsurface kerogen (e.g. Type IIs kerogen for example of the Ghareb formation) is that the respective reaction rates may be significantly different at pyrolysis or near-pyrolysis temperatures. 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. As evident from FIG. 2, (i) at sub-pyrolysis temperatures, the pyrolysis reaction rates for both kerogens are negligible; (ii) at low pyrolysis temperatures, the pyrolysis reaction rate for low-sulfur kerogen is ‘significant’ and greatly exceeds that of the high-sulfur kerogen; and (ii) at higher pyrolysis temperatures, the pyrolysis reaction rate for low-sulfur kerogen is at least on the same order of magnitude as that of high-sulfur kerogen, eventually overtaking it at increasing temperatures.
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. electrical heaters or molten salt heaters) are deployed within a target portion 284 of the hydrocarbon-containing subsurface formation 280. Thermal energy is transferred from the heaters 220 to the target portion 284 so as to heat the target portion 284 and to eventually pyrolyze kerogen therein. As evident from FIG. 2, 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.
As illustrated in FIG. 3A, one or more production wells 224 are also deployed within the pyrolyzed target portion 284. When sufficiently heated by heaters 220, formation fluids including formation gases are recovered via production well(s) 224. For example, a gas mixture stream 296 of pyrolysis formation gases generated by pyrolysis of the target portion 284 may exit the production well(s) 224. As illustrated in FIG. 7, 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. However, 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. 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). Each curve has a minimum of ‘0’ and a maximum of ‘1’ 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.
In FIG. 4, time (T₁) refers to the time when the temperature first reaches T₁, and time (T₂) refers to the time when the temperature first reaches T₂.
In one non-example relating to the Ghareb formation in Jordan, T₁can be about 220 or about 230 or about 240 or about 250 degrees Celsius and T₂can be about 300 or about 290 degrees Celsius.
Initially, a bulk temperature of the target portion 284 of the kerogen or bitumen formation 280 is very low (i.e. less than time (T₁)) and a rate of pyrolysis is insignificant. Once the bulk temperature reaches a certain temperature range between T₁and T₂corresponding to the low temperature pyrolysis regime of FIG. 2, the reaction rate R₁of “REACTION 1” is significant, while the reaction rate R₂of “REACTION 2” remains insignificant. At this time, a formation gas mixture stream 296 is rich in acid gases while a concentration of H₂-rich and hydrocarbon gas (i.e. the valuable gases) therein is relatively low. The time window corresponding to the (T₁, T₂) 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.
During a later stage of pyrolysis, when the bulk temperature of the target portion 284 of the kerogen or bitumen exceeds T₂and corresponds to the high pyrolysis temperature regime of FIG. 2, the normalized amount of produced valuable gases is relatively high, and the concentration of valuable gases within gas mixture stream 296 is also significant. This is represented in FIG. 4 as the period of time after time (T₂).
As noted above, both 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 (T₁), the bulk temperature of the target portion 284 of kerogen or bitumen formation 280 increases steadily—for example, at a substantially constant rate. When the temperature reaches the low pyrolysis temperature regime between T₁and T₂, heaters continue to operate at or near full power, and a bulk temperature of the of kerogen or bitumen formation 280 continues to increase at a rate on the same order of magnitude as that observed at lower temperatures below T₁. At bulk temperatures above T₂, in the high pyrolysis temperature regime, the bulk temperature of the formation increases at a much lower rate and/or remains substantially constant. As illustrated in FIG. 5, after time (T₂), the majority (e.g. a significant or very significant majority) of hydrocarbon fluids are produced—e.g. recovered via production well(s) 224.
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. For temperatures less than 220 degrees Celsius, the absolute flow rate of pyrolysis formation gases Q is very small. At higher temperatures, the flow rate is significantly larger and the concentration of acid gases (H₂S and CO_X) within the flow of formation gases from the oil shale sample is quite significant. At higher temperatures (e.g. above 300 degrees Celsius), 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.
In the apparatus of FIG. 7, a gas detector 270 (for example, a Gas Chomotography instrument) 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).
In the apparatus of FIG. 3 all gases of the gas mixture stream 296 of pyrolysis formation gases are directed to a gas treatment facility 282. In contrast, in FIG. 7, flow control 224 may direct gases of gas mixture stream 296 to deep injection well 260. In a first example related to time-based separation of acid gases from valuable gases, (i) for a first period of time (e.g. corresponding to the time window TW_T₁ _—T₂defined by (time (T₁), time (T₂))), 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 time (T₂), all gases of formation gas mixture stream 296 are directed by flow control 224 to gas treatment facility 282.
In the example of FIG. 3, 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_T₁ _—T₂and when the bulk temperature of the target portion 284 may mix with ‘later pyrolysis gases’ that formed after time (T₂). As noted above, the early pyrolysis gases are H₂S-rich and CO_X-rich and are characterized by at most low concentrations of H₂and hydrocarbon gases while the concentration of H₂S and CO_Xwithin hydrocarbon-rich and H₂-rich ‘later gases’ is much lower. In order to obtain, from the mixture of the early pyrolysis gases and the later pyrolysis gases, a product of valuable gases that is relatively free of acid gases, it is necessary to subject a relatively large quantity of gases (i.e. the combined quantity of early and later pyrolysis gases) to a gas component separation process—for example, within gas treatment facility 282.

Additional Discussion Related to FIGS. 3B-3D

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. In different embodiments, 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.
Examples of hydrocarbon-containing rocks are kerogen-containing rocks (e.g. mined oil shale or mined coal) and bitumen-containing rocks (e.g. tar sands).
In the description and claims of the present application, 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.
All references cited herein are incorporated by reference in their entirety. Citation of a reference does not constitute an admission that the reference is prior art.
The articles “a” and “an” are used herein to refer to one or to more than one. (i.e., to at least one) of the grammatical object of the article. By way of example, “an element” means one element or more than one element.
The term “including” is used herein to mean, and is used interchangeably with, the phrase “including but not limited” to.
The term “or” is used herein to mean, and is used interchangeably with, the term “and/or,” unless context clearly indicates otherwise.
The term “such as” is used herein to mean, and is used interchangeably, with the phrase “such as but not limited to”.
The present invention has been described using detailed descriptions of embodiments thereof that are provided by way of example and are not intended to limit the scope of the invention. The described embodiments comprise different features, not all of which are required in all embodiments of the invention. Some embodiments of the present invention utilize only some of the features or possible combinations of the features. Variations of embodiments of the present invention that are described and embodiments of the present invention comprising different combinations of features noted in the described embodiments will occur to persons skilled in the art.

Claims

What is claimed is:

1. A pyrolysis method comprising:

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.

2. A pyrolysis method comprising:

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.

3. A pyrolysis method comprising:

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.

4. A pyrolysis method comprising:

b. 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

c. sequestering the acid gases.

5. A pyrolysis method comprising:

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.

6. The method of any preceding claim wherein the heaters are subsurface heaters.

7. A pyrolysis method comprising:

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;

d. contingent upon an acid gas concentration being below a threshold value, subjecting pyrolysis gases of the stream to sequestration; and

ii. subjecting a lesser fraction of the stream to a sequestration.

8. A pyrolysis method comprising:

b. heating the bed of rocks so as to initiate pyrolysis of kerogen and/or bitumen therein thereby generating pyrolysis formation gases so that:

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

9. A pyrolysis method comprising:

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.

10. A pyrolysis method comprising:

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.

11. A pyrolysis method comprising:

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.

12. The method of any of claims 7-11 wherein the interior region is maintained under anoxic conditions during the heating.

13. The method of any of claims 7-12 wherein the enclosure is an excavated enclosure.

14. The method of any of claims 7-12 any previous claim wherein the enclosure is a pit or an impoundment.

15. The method of any preceding claim wherein the sequestration is subsurface sequestration, for example, deep well sequestration.

16. The method of any preceding claim wherein the sequestration is subsurface sequestration, for example, deep well sequestration in a well-confined saline aquifer gas cap.

17. The method of any preceding claim wherein the acid gas threshold value is between 70% and 95%,

18. The method of any preceding claim wherein the acid gas threshold value is least 85% and/or at most 90%.

19. The method of any preceding claim wherein the sequestration is carried out immediately.

20. The method of any preceding claim wherein the sequestration is carried out at a much later time.

21. The method of any preceding claim wherein the subsurface formation is an oil shale formation or a coal formation or a bitumen formation.

22. The method of any preceding claim wherein the kerogen is type IIs kerogen or the bitumen is derived from type IIs kerogen.

23. The method of any preceding claim wherein the kerogen is sulfur-rich type IIs kerogen or the bitumen is derived from sulfur-rich type IIs kerogen.

24. The method of any preceding claim wherein the acid gas separation process is carried out in an amine unit.

25. The method of any preceding claim wherein the acid gas elimination process is carried out in a caustic system, for example, based upon sodium hydroxide or potassium hydroxide.