2. Description of Related Art Hydrocarbons obtained from subterranean (e. g. , sedimentary) formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material within a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material within the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.

Obtaining permeability within an oil shale formation (e. g. , between injection and production wells) tends to be difficult because oil shale is often substantially impermeable. Many methods have attempted to link injection and production wells, including: hydraulic fracturing such as methods investigated by Dow Chemical and Laramie Energy Research Center ; electrical fracturing (e. g. , by methods investigated by Laramie Energy Research Center); acid leaching of limestone cavities (e. g. , by methods investigated by Dow Chemical); steam injection into permeable nahcolite zones to dissolve the nahcolite (e. g. , by methods investigated by Shell Oil and Equity Oil); fracturing with chemical explosives (e. g. , by methods investigated by Talley Energy Systems); fracturing with nuclear explosives (e. g. , by methods investigated by Project Bronco); and combinations of these methods. Many of such methods, however, have relatively high operating costs and lack sufficient injection capacity. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations containing lean and rich zones.

SUMMARY OF THE INVENTION In an embodiment, hydrocarbons within a hydrocarbon containing formation (e. g. , a formation containing coal, oil shale, heavy hydrocarbons, or a combination thereof) may be converted in situ within the formation to yield a mixture of relatively high quality hydrocarbon products, hydrogen, and/or other products. One or more heaters may be used to heat a portion of the hydrocarbon containing formation to temperatures that allow pyrolysis of the hydrocarbons. Hydrocarbons, hydrogen, and other formation fluids may be removed from the formation

through one or more production wells. In some embodiments, formation fluids may be removed in a vapor phase.

In other embodiments, formation fluids may be removed in liquid and vapor phases or in a liquid phase.

Temperature and pressure in at least a portion of the formation may be controlled during pyrolysis to yield improved products from the formation.

In an embodiment, a method for treating a hydrocarbon containing formation in situ includes providing heat from one or more heaters to at least a portion of the formation. Heat may be allowed to transfer from the one or more heaters to a first part of the formation. The transferred heat may pyrolyze at least some hydrocarbons within the first part of the formation. A mixture may be produced through a second part of the formation. The produced mixture may include at least some pyrolyzed hydrocarbons from the first part of the formation. In certain embodiments, the second part of the formation may have a higher permeability than the first part of the formaton.

BRIEF DESCRIPTION OF THE DRAWINGS Advantages of the present invention may become apparent to those skilled in the art with the benefit of the following detailed description of the preferred embodiments and upon reference to the accompanying drawings in which: FIG. 1 depicts an illustration of stages of heating a hydrocarbon containing formation.

FIG. 2 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation.

FIG. 3 depicts an embodiment of heater wells located in a hydrocarbon containing formation.

FIG. 4 depicts a cross-sectional representation of an embodiment for treating a lean zone and a rich zone of a formation.

While the invention is susceptible to various modifications and alternative forms, specific embodiments thereof are shown by way of example in the drawings and may herein be described in detail. The drawings may not be to scale. It should be understood, however, that the drawings and detailed description thereto are not intended to limit the invention to the particular form disclosed, but on the contrary, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the present invention as defined by the appended claims.

DETAILED DESCRIPTION OF THE INVENTION The following description generally relates to systems and methods for treating a hydrocarbon containing formation (e. g. , a formation containing coal (including lignite, sapropelic coal, etc. ), oil shale, carbonaceous shale, shungites, kerogen, bitumen, oil, kerogen and oil in a low permeability matrix, heavy hydrocarbons, asphaltites, natural mineral waxes, formations wherein kerogen is blocking production of other hydrocarbons, etc. ). Such formations may be treated to yield relatively high quality hydrocarbon products, hydrogen, and other products.

"Hydrocarbons"are generally deEmed as molecules formed primarily by carbon and hydrogen atoms.

Hydrocarbons may also include other elements, such as, but not limited to, halogens, metallic elements, nitrogen, oxygen, and/or sulfur. Hydrocarbons may be, but are not limited to, kerogen, bitumen, pyrobitumen, oils, natural mineral waxes, and asphaltites. Hydrocarbons may be located within or adjacent to mineral matrices within the earth. Matrices may include, but are not limited to, sedimentary rock, sands, silicilytes, carbonates, diatomites, and other porous media. "Hydrocarbon fluids"are fluids that include hydrocarbons. Hydrocarbon fluids may include,

entrain, or be entrained in non-hydrocarbon fluids (e. g. , hydrogen ("H2"), nitrogen ("N2"), carbon monoxide, carbon dioxide, hydrogen sulfide, water, and ammonia).

A"formation"includes one or more hydrocarbon containing layers, one or more non-hydrocarbon layers, an overburden, and/or an underburden. An"overburden"and/or an"underburden"include one or more different types of impermeable materials. For example, overburden and/or underburden may include rock, shale, mudstone, or wet/tight carbonate (i. e. , an impermeable carbonate without hydrocarbons). In some embodiments of in situ conversion processes, an overburden and/or an underburden may include a hydrocarbon containing layer or hydrocarbon containing layers that are relatively impermeable and are not subjected to temperatures during in situ conversion processing that result in significant characteristic changes of the hydrocarbon containing layers of the overburden and/or underburden. For example, an underburden may contain shale or mudstone. In some cases, the overburden and/or underburden may be somewhat permeable.

"Kerogen"is a solid, insoluble hydrocarbon that has been converted by natural degradation (e. g., by diagenesis) and that principally contains carbon, hydrogen, nitrogen, oxygen, and sulfur. Coal and oil shale are typical examples of materials that contain kerogens. "Oil"is a fluid containing a mixture of condensable hydrocarbons.

The terms"formation fluids"and"produced fluids"refer to fluids removed from a hydrocarbon containing formation and may include pyrolyzation fluid, synthesis gas, mobilized hydrocarbon, and water (steam). The term "mobilized fluid"refers to fluids within the formation that are able to flow because of thermal treatment of the formation. Formation fluids may include hydrocarbon fluids as well as non-hydrocarbon fluids.

A"heat source"is any system for providing heat to at least a portion of a formation substantially by conductive and/or radiative heat transfer. For example, a heat source may include electric heaters such as an insulated conductor, an elongated member, and/or a conductor disposed within a conduit. A heat source may also include heat sources that generate heat by burning a fuel external to or within a formation, such as surface burners, downhole gas burners, flameless distributed combustors, and natural distributed combustors. In addition, it is envisioned that in some embodiments heat provided to or generated in one or more heat sources may be supplied by other sources of energy. The other sources of energy may directly heat a formation, or the energy may be applied to a transfer media that directly or indirectly heats the formation. It is to be understood that one or more heat sources that are applying heat to a formation may use different sources of energy. For example, for a given formation some heat sources may supply heat from electric resistance heaters, some heat sources may provide heat from combustion, and some heat sources may provide heat from one or more other energy sources (e. g. , chemical reactions, solar energy, wind energy, biomass, or other sources of renewable energy). A chemical reaction may include an exothermic reaction (e. g. , an oxidation reaction). A heat source may include a heater that provides heat to a zone proximate and/or surrounding a heating location such as a heater well.

A"heater"is any system for generating heat in a well or a near wellbore region. Heaters may be, but are not limited to, electric heaters, burners, combustors that react with material in or produced from a formation (e. g., natural distributed combustors), and/or combinations thereof. A"unit of heat sources"refers to a number of heat sources that form a template that is repeated to create a pattern of heat sources within a formation.

The term"wellbore"refers to a hole in a formation made by drilling or insertion of a conduit into the formation. A wellbore may have a substantially circular cross section, or other cross-sectional shapes (e. g. , circles, ovals, squares, rectangles, triangles, slits, or other regular or irregular shapes). As used herein, the terms"well"and "opening, "when referring to an opening in the formation may be used interchangeably with the term"wellbore."

"Pyrolysis"is the breaking of chemical bonds due to the application of heat. For example, pyrolysis may include transforming a compound into one or more other substances by heat alone. Heat may be transferred to a section of the formation to cause pyrolysis.

"Pyrolyzation fluids"or"pyrolysis products"refers to fluid produced substantially during pyrolysis of hydrocarbons. Fluid produced by pyrolysis reactions may mix with other fluids in a formation. The mixture would be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone"refers to a volume of a formation (e. g. , a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

"Fluid pressure"is a pressure generated by a fluid within a formation. "Lithostatic pressure" (sometimes referred to as"lithostatic stress") is a pressure within a formation equal to a weight per unit area of an overlying rock mass. "Hydrostatic pressure"is a pressure within a formation exerted by a column of water.

"Thickness"of a layer refers to the thickness of a cross section of a layer, wherein the cross section is normal to a face of the layer.

Hydrocarbons in formations may be treated in various ways to produce many different products. In certain embodiments, such formations may be treated in stages. FIG. 1 illustrates several stages of heating a hydrocarbon containing formation. FIG. 1 also depicts an example of yield (barrels of oil equivalent per ton) (y axis) of formation fluids from a hydrocarbon containing formation versus temperature (°C) (x axis) of the formation.

Desorption of methane and vaporization of water occurs during stage 1 heating. Heating of the formation through stage 1 may be performed as quickly as possible. For example, when a hydrocarbon containing formation is initially heated, hydrocarbons in the formation may desorb adsorbed methane. The desorbed methane may be produced from the formation. If the hydrocarbon containing formation is heated further, water within the hydrocarbon containing formation may be vaporized. Water may occupy, in some hydrocarbon containing formations, between about 10 % to about 50 % of the pore volume in the formation. In other formations, water may occupy larger or smaller portions of the pore volume. Water typically is vaporized in a formation between about 160 °C and about 285 °C for pressures of about 6 bars absolute to 70 bars absolute. In some embodiments, the pressure in a formation may be maintained during an in situ conversion process between about 2 bars absolute and about 70 bars absolute. In some embodiments, the vaporized water may produce wettability changes in the formation and/or increase formation pressure. The wettability changes and/or increased pressure may affect pyrolysis reactions or other reactions in the formation. In certain embodiments, the vaporized water may be produced from the formation. In other embodiments, the vaporized water may be used for steam extraction and/or distillation in the formation or outside the formation. Removing the water from and increasing the pore volume in the formation may increase the storage space for hydrocarbons within the pore volume.

After stage 1 heating, the formation may be heated further, such that a temperature within the formation reaches (at least) an initial pyrolyzation temperature (e. g. , a temperature at the lower end of the temperature range shown as stage 2). Hydrocarbons within the formation may be pyrolyzed throughout stage 2. A pyrolysis temperature range may vary depending on types of hydrocarbons within the formation. A pyrolysis temperature range may include temperatures between about 250 °C and about 900 °C. A pyrolysis temperature range for producing desired products may extend through only a portion of the total pyrolysis temperature range. In some embodiments, a pyrolysis temperature range for producing desired products may include temperatures between about 250 °C to about 400 °C. If a temperature of hydrocarbons in a formation is slowly raised through a temperature range from about 250 °C to about 400 °C, production of pyrolysis products may be substantially

complete when the temperature approaches 400 °C. Heating the hydrocarbon containing formation with a plurality of heat sources may establish thermal gradients around the heat sources that slowly raise the temperature of hydrocarbons in the formation through a pyrolysis temperature range.

In some in situ conversion embodiments, a temperature of the hydrocarbons to be subjected to pyrolysis may not be slowly increased throughout a temperature range from about 250 °C to about 400 °C. The hydrocarbons in the formation may be heated to a desired temperature (e. g. , about 325 °C). Other temperatures may be selected as the desired temperature. Energy input into the formation from the heat sources may be adjusted to maintain the temperature in the formation substantially at the desired temperature. The hydrocarbons may be maintained substantially at the desired temperature until pyrolysis declines such that production of desired formation fluids from the formation becomes uneconomical.

In some in situ conversion process embodiments, a portion of a hydrocarbon containing formation may be heated at a heating rate in a range from about 0. 1 °C/day to about 50 °C/day or, in some embodiments, about 0.1 °C/day to about 10 °C/day. For example, a majority of hydrocarbons may be produced from a formation heated at a heating rate within a range of about 0.1 °C/day to about 10 °C/day. In addition, a hydrocarbon containing formation may be heated at a rate of less than about 0. 7 °C/day through a significant portion of a pyrolysis temperature range.

The pyrolysis temperature range may include a range of temperatures as described in above embodiments. For example, the heated portion may be heated at such a rate for a time greater than 50% of the time needed to span the temperature range, more than 75% of the time needed to span the temperature range, or more than 90% of the time needed to span the temperature range.

Formation fluids including pyrolyzation fluids may be produced from the formation. The pyrolyzation fluids may include, but are not limited to, hydrocarbons, hydrogen, carbon dioxide, carbon monoxide, hydrogen sulfide, ammonia, nitrogen, water, and mixtures thereof. As the temperature of the formation increases, the amount of condensable hydrocarbons in the produced formation fluid tends to decrease. At high temperatures, the formation may produce mostly methane and/or hydrogen. If a hydrocarbon containing formation is heated throughout an entire pyrolysis range, the formation may produce only small amounts of hydrogen towards an upper limit of the pyrolysis range. After all of the available hydrogen is depleted, a minimal amount of fluid production from the formation will typically occur.

After pyrolysis of hydrocarbons, a large amount of carbon and some hydrogen may still be present in the formation. A significant portion of remaining carbon in the formation can be produced from the formation in the form of synthesis gas. Synthesis gas generation may take place during stage 3 heating depicted in FIG. 1. Stage 3 may include heating a hydrocarbon containing formation to a temperature sufficient to allow synthesis gas generation. For example, synthesis gas may be produced within a temperature range from about 400 °C to about 1200 °C.

A hydrocarbon containing formation may have a number of properties that depend on a composition of the hydrocarbons within the formation. Such properties may affect the composition and amount of products that are produced from a hydrocarbon containing formation during in situ conversion. Properties of a hydrocarbon containing formation may be used to determine if and/or how a hydrocarbon containing formation is to be subjected to in situ conversion.

For example, a formation may be selected based on richness, thickness, and/or depth (i. e. , thickness of overburden) of the formation. In addition, the types of fluids producible from the formation may be a factor in the selection of a formation for in situ conversion. In certain embodiments, the quality of the fluids to be produced may

be assessed in advance of treatment. Assessment of the products that may be produced from a formation may generate significant cost savings since only formations that will produce desired products needed to be subjected to in situ conversion. Properties that may be used to assess hydrocarbons in a formation include, but are not limited to, an amount of hydrocarbon liquids that may be produced from the hydrocarbons, a likely API gravity of the produced hydrocarbon liquids, an amount of hydrocarbon gas producible from the formation, and/or an amount of carbon dioxide and water that in situ conversion will generate.

A hydrocarbon containing formation may be selected for treatment based on additional factors such as, but not limited to, thickness of hydrocarbon containing layers within the formation, assessed liquid production content, location of the formation, and depth of hydrocarbon containing layers. A hydrocarbon containing formation may include multiple layers. Such layers may include hydrocarbon containing layers, as well as layers that are hydrocarbon free or have relatively low amounts of hydrocarbons. Conditions during formation may determine the thickness of hydrocarbon and non-hydrocarbon layers in a hydrocarbon containing formation. A hydrocarbon containing formation to be subjected to in situ conversion will typically include at least one hydrocarbon containing layer having a thickness sufficient for economical production of formation fluids. Richness of a hydrocarbon containing layer may be a factor used to determine if a formation will be treated by in situ conversion. A thin and rich hydrocarbon layer may be able to produce significantly more valuable hydrocarbons than a much thicker, less rich hydrocarbon layer. Producing hydrocarbons from a formation that is both thick and rich is desirable.

Each hydrocarbon containing layer of a formation may have a potential formation fluid yield or richness.

The richness of a hydrocarbon layer may vary in a hydrocarbon layer and between different hydrocarbon layers in a formation. Richness may depend on many factors including the conditions under which the hydrocarbon containing' layer was formed, an amount of hydrocarbons in the layer, and/or a composition of hydrocarbons in the layer.

Richness of a hydrocarbon layer may be estimated in various ways.

An in situ conversion process may be used to treat formations with hydrocarbon layers that have thicknesses greater than about 10 m. Formations having hydrocarbon layers that are less than 10 m thick may also be treated using an in situ conversion process. In some in situ conversion embodiments of thin hydrocarbon layer formations, heat sources may be inserted in or adjacent to the hydrocarbon layer along a length of the hydrocarbon layer (e. g. , with horizontal or directional drilling). Heat losses to layers above and below the thin hydrocarbon layer or thin hydrocarbon layers may be offset by an amount and/or quality of fluid produced from the formation.

FIG. 2 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation. Heat sources 100 may be placed within at least a portion of the hydrocarbon containing formation. Heat sources 100 may include, for example, electric heaters such as insulated conductors, conductor-in-conduit heaters, surface burners, flameless distributed combustors, and/or natural distributed combustors. Heat sources 100 may also include other types of heaters. Heat sources 100 may provide heat to at least a portion of a hydrocarbon containing formation. Energy may be supplied to the heat sources 100 through supply lines 102. The supply lines may be structurally different depending on the type of heat source or heat sources being used to heat the formation. Supply lines for heat sources may transmit electricity for electric heaters, may transport fuel for combustors, or may transport heat exchange fluid that is circulated within the formation.

Production wells 104 may be used to remove formation fluid from the formation. Formation fluid produced from production wells 104 may be transported through collection piping 106 to treatment facilities 108.

Formation fluids may also be produced from heat sources 100. For example, fluid may be produced from heat sources 100 to control pressure within the formation adjacent to the heat sources. Fluid produced from heat sources

100 may be transported through tubing or piping to collection piping 106 or the produced fluid may be transported through tubing or piping directly to treatment facilities 108. Treatment facilities 108 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and other systems and units for processing produced formation fluids.

An in situ converion system for treating hydrocarbons may include barrier wells 110. In some embodiments, barriers may be used to inhibit migration of fluids (e. g. , generated fluids and/or groundwater) into and/or out of a portion of a formation undergoing an in situ conversion process. Barriers may include, but are not limited to naturally occurring portions (e. g. , overburden and/or underburden), freeze wells, frozen barrier zones, low temperature barrier zones, grout walls, sulfur wells, dewatering wells, injection wells, a barrier formed by a gel produced in the formation, a barrier formed by precipitation of salts in the formation, a barrier formed by a polymerization reaction in the formation, sheets driven into the formation, or combinations thereof.

In some embodiments, a perimeter barrier above a treatment area may be formed as a ground cover placed at or near the surface of the formation. Such a perimeter barrier may allow for treatment of a formation wherein a hydrocarbon layer to be processed is close to the surface.

Hydrocarbons to be subjected to in situ conversion may be located under a large area. The in situ conversion system may be used to treat small portions of the formation, and other sections of the formation may be treated as time progresses. In an embodiment of a system for treating a formation (e. g. , an oil shale formation), a field layout for 24 years of development may be divided into 24 individual plots that represent individual drilling years. Each plot may include 120"tiles" (repeating matrix patterns) wherein each plot is made of 6 rows by 20 columns of tiles. Each tile may include 1 production well and 12 or 18 heater wells. The heater wells may be placed in an, equilateral triangle pattern with a well spacing of about 12 m. Production wells may be located in centers of equilateral triangles of heater wells, or the production wells may be located approximately at a midpoint between two adjacent heater wells.

There will typically be many heated portions, as well as many selected sections within the pattern of heat sources. In some embodiments, a large spacing may provide for a relatively slow heating rate of hydrocarbon material. The slow heating rate may allow for pyrolysis of hydrocarbon material with minimal coking or no coking within the formation away from areas in the vicinity of the heat sources. Heating from heat sources allows the selected section to reach pyrolysis temperatures so that all hydrocarbons within the selected section may be subject to pyrolysis reactions. In some in situ conversion embodiments, a majority of pyrolysis fluids are produced when the selected section is within a range from about 0 m to about 25 m from a heat source.

In an in situ conversion process embodiment, a heating rate may be controlled to minimize costs associated with heating a selected section. The costs may include, for example, input energy costs and equipment costs. In certain embodiments, a cost associated with heating a selected section may be minimized by reducing a heating rate when the cost associated with heating is relatively high and increasing the heating rate when the cost associated with heating is relatively low. For example, a heating rate of about 330 watts/m may be used when the associated cost is relatively high, and a heating rate of about 1640 watts/m may be used when the associated cost is relatively low. In an embodiment, the heating rate may be varied from a higher heating rate during low energy usage times, such as during the night, to a lower heating rate during high energy usage times, such as during the day.

As shown in FIG. 2, in addition to heat sources 100, one or more production wells 104 will typically be placed within the portion of the hydrocarbon containing formation. Formation fluids may be produced through production well 104. In some embodiments, production well 104 may include a heat source. The heat source may

heat the portions of the formation at or near the production well and allow for vapor phase removal of formation fluids. The need for high temperature pumping of liquids from the production well may be reduced or eliminated.

Avoiding or limiting high temperature pumping of liquids may significantly decrease production costs. Providing heating at or through the production well may: (1) inhibit condensation and/or refluxing of production fluid when such production fluid is moving in the production well proximate the overburden, (2) increase heat input into the formation, and/or (3) increase formation permeability at or proximate the production well. In some in situ conversion process embodiments, an amount of heat supplied to production wells is significantly less than an amount of heat applied to heat sources that heat the formation.

Because permeability and/or porosity increases in the heated formation, produced vapors may flow considerable distances through the formation with relatively little pressure differential. Increases in permeability may result from a reduction of mass of the heated portion due to vaporization of water, removal of hydrocarbons, and/or creation of fractures. Fluids may flow more easily through the heated portion. In some embodiments, production wells may be provided in upper portions of hydrocarbon layers.

FIG. 3 illustrates an embodiment of hydrocarbon containing layer 112 that may be at a near-horizontal angle with respect to an upper surface of ground 114. An angle of hydrocarbon containing layer 112, however, may vary. For example, hydrocarbon containing layer 112 may dip or be steeply dipping. Economically viable production of a steeply dipping hydrocarbon containing layer may not be possible using presently available mining methods. As shown in FIG. 3, production wells 104 may extend into a hydrocarbon containing formation near the top of heated portion 116 heated by heater well 118. Extending production wells significantly into the depth of the heated hydrocarbon layer may be unnecessary.

A heater may be placed in an opening in a hydrocarbon containing formation. The heater may be placed in an uncased opening in the hydrocarbon containing formation. Using an uncased opening may facilitate retrieval of the heater from the well, if necessary. Using an uncased opening may significantly reduce heat source capital cost by eliminating a need for a portion of casing able to withstand high temperature conditions. In some heat source embodiments, a heater may be placed within a casing in the formation; may be cemented within the formation; or may be packed in an opening with sand, gravel, or other fill material. The heater may be supported on a support member positioned within the opening. The support member may be a cable, rod, or a conduit (e. g. , a pipe). The support member may be made of a metal, ceramic, inorganic material, or combinations thereof. Portions of a support member may be exposed to formation fluids and heat during use, so the support member may be chemically resistant and thermally resistant.

Placing the heater in an uncased opening in the hydrocarbon containing formation may allow heat transfer from the heater to the formation by radiation as well as conduction. Some heat may be transferred by conduction or convection of heat due to gases present in the opening. Heat transfer by radiation is typically more efficient than by conduction, so the heaters may be operated at lower temperatures in an open wellbore. Conductive heat transfer during initial operation of a heat source may be enhanced by the addition of a gas in the opening. The gas may be maintained at a pressure up to about 27 bars absolute. The gas may include, but is not limited to, carbon dioxide and/or helium. A heater in an open wellbore may advantageously be free to expand or contract to accommodate thermal expansion and contraction.

An in situ process for hydrocarbons may include monitoring a rate of temperature increase at a production well. A temperature within a portion of a hydrocarbon containing formation, however, may be measured at various locations within the portion of the formation. An in situ process may include monitoring a temperature of the

portion at a midpoint between two adjacent heat sources. The temperature may be monitored over time to allow for calculation of rate of temperature increase. A rate of temperature increase may affect a composition of formation fluids produced from the formation. Energy input into a formation may be adjusted to change a heating rate of the formation based on calculated rate of temperature increase in the formation to promote production of desired products.

Fluid generated within a hydrocarbon containing formation may move a considerable distance through the hydrocarbon containing formation as a vapor. The considerable distance may be over 1000 m depending on various factors (e. g. , permeability of the formation, properties of the fluid, temperature of the formation, and pressure gradient allowing movement of the fluid). Due to increased permeability in formations subjected to in situ conversion and formation fluid removal, production wells may only need to be provided in every other unit of heat sources or every third, fourth, fifth, or sixth units of heat sources.

During an in situ process, production wells may be operated such that the production wells are at a lower pressure than other portions of the formation. In some embodiments, a vacuum may be drawn at the production wells. Maintaining the production wells at lower pressures may inhibit fluids in the formation from migrating outside of the in situ treatment area.

Subsurface pressure in a hydrocarbon containing formation may correspond to the fluid pressure generated within the formation. Heating hydrocarbons within a hydrocarbon containing formation may generate fluids by pyrolysis. The generated fluids may be vaporized within the formation. Vaporization and pyrolysis reactions may increase the pressure within the formation. Fluids that contribute to the increase in pressure may include, but are not limited to, fluids produced during pyrolysis and water vaporized during heating. As temperature within a selected section of a heated portion of the formation increase, a pressure within the selected section may increase as a result of increased fluid generation and vaporization of water. Controlling a rate of fluid removal from the formation may allow for control of pressure in the formation.

In some embodiments, pressure within a selected section of a heated portion of a hydrocarbon containing formation may vary depending on factors such as depth, distance from a heat source, a richness of the hydrocarbons within the hydrocarbon containing formation, and/or a distance from a producer well. Pressure within a formation may be determined at a number of different locations (e. g. , near or at production wells, near or at heat sources, or at monitor wells).

Heating of a hydrocarbon containing formation to a pyrolysis temperature range may occur before substantial permeability has been generated within the hydrocarbon containing formation. An initial lack of permeability may inhibit the transport of generated fluids from a pyrolysis zone within the formation to a production well. As heat is initially transferred from a heat source to a hydrocarbon containing formation, a fluid pressure within the hydrocarbon containing formation may increase proximate a heat source. Such an increase in fluid pressure may be caused by generation of fluids during pyrolysis of at least some hydrocarbons in the formation. The increased fluid pressure may be released, monitored, altered, and/or controlled through the heat source. For example, the heat source may include a valve that allows for removal of some fluid from the formation.

In some heat source embodiments, the heat source may include an open wellbore configuration that inhibits pressure damage to the heat source.

In some in situ conversion process embodiments, pressure generated by expansion of pyrolysis fluids or other fluids generated in the formation may be allowed to increase although an open path to the production well or any other pressure sink may not yet exist in the formation. The fluid pressure may be allowed to increase towards a

lithostatic pressure. Fractures in the hydrocarbon containing formation may form when the fluid approaches the lithostatic pressure. For example, fractures may form from a heat source to a production well. The generation of fractures within the heated portion may relieve some of the pressure within the portion.

When permeability or flow channels to production wells are established, pressure within the formation may be controlled by controlling production rate from the production wells. In some embodiments, a back pressure may be maintained at production wells or at selected production wells to maintain a selected pressure within the heated portion.

A formation (e. g. , an oil shale formation) may include one or more lean zones. Lean zones may include zones with a relatively low kerogen content (e. g. , less than about 0.06 L/kg in oil shale). Rich zones may include zones with a relatively high kerogen content (e. g., greater than about 0.06 L/kg in oil shale). Lean zones may exist at an upper or lower boundary of a rich zone and/or may exist as lean zone layers between layers of rich zone layers. Generally, lean zones may be more permeable and include more brittle material than rich zones. In addition, rich zones typically have a lower thermal conductivity than lean zones. For example, lean zones may include zones through which fluids (e. g. , water) can flow. In some cases, however, lean zones may have lower permeabilities and/or include somewhat less brittle material. In an in situ process for treating a formation, heat may be applied to rich zones with substantial amounts of hydrocarbons to pyrolyze and produce hydrocarbons from the rich zones. Applying heat to lean zones may be inhibited to avoid creating fractures within the lean zones (e. g., when the lean zone is at an outer boundary of the formation).

In certain embodiments, heat may be applied to a lean zone (e. g. , a lean zone between two rich zones) to create and propagate fractures within the lean zone. Applying heat to a lean zone and creating fractures within the lean zone may allow for earlier production of hydrocarbons from a formation. In some embodiments, heating of the lean zone may not be needed as fractures or high permeability is initially present within the lean zone. Formation fluids may flow through a permeable lean zone more rapidly than through other portions of a formation. Formation fluids may be produced through a production well earlier during heating of the formation in the presence of a permeable lean zone. The permeable lean zone may provide a pathway for the flow of fluids between the heat front where fluids are pyrolyzed and the production well. Production of formation fluids through the permeable lean zone may increase the production of fluids as liquids, inhibit pressure buildup in the formation, inhibit failure/collapse of wells due to high pressures, and/or allow for convective heat transfer through the fractures.

FIG. 4 depicts a cross-sectional representation of an embodiment for treating lean zones 120 and rich zones 122 of a formation. Lean zones 120 and rich zones 122 are below overburden 124. In some embodiments, lean zones 120 may be relatively permeable sections of the formation. For example, lean zones 120 may have an average permeability thickness product of greater than about 100 millidarcy feet. In certain embodiments, lean zones 120 may have an average permeability thickness product of greater than about 1000 millidarcy feet or greater than about 5000 millidarcy feet. Rich zones 122 may be sections of the formation that are selected for treatment based on a richness of the section. Rich zones 122 may have an initial average permeability thickness product of less than about 10 millidarcy feet. Certain rich zones may have an initial average permeability thickness product of less than about 1 millidarcy feet or less than about 0.5 millidarcy feet.

Heat source 100 may be placed through overburden 124 and into opening 126 Reinforcing material 128 (e. g. , cement) may seal a portion of opening 126 to overburden 124. Heat source 100 may apply heat to lean zones 120 and/or rich zones 122. In some embodiments, heat source 100 may include a conductor with a thickness that is

adjusted to provide more heat to rich zones 122 than lean zones 120 (i. e. , the thickness of the conductor is larger proximate the lean zones than the thickness of the conductor proximate the rich zones).

In certain embodiments, rich zones 122 may not fracture. For example, the rich zones may have a ductility that is high enough to inhibit the formation of fractures. A formation (e. g. , an oil shale formation) may have one or more lean zones 120 and one or more rich zones 122 that are layered throughout the formation as shown in FIG. 4.

Formation fluids formed in rich zones 122 may be produced through pre-existing fractures in lean zone 120. In some embodiments, lean zone 120 may have a permeability sufficiently high to allow production of fluids. This high permeability may be initially present in the lean zone because of, for example, water flow through the lean zone that leached out minerals over geological time prior to initiation of the in situ conversion process. In some embodiments, the application of heat to the formation from heat sources may produce, or increase the size of, fractures 130 and/or increase the permeability in lean zones 120. Fractures 130 may increase the permeability of lean zones 120 by providing a pathway for fluids to propagate through the lean zones.

During early times of heating, permeability may be created near opening 126. Permeability may be created in permeable zone 132 adjacent opening 126. Permeable zone 132 will increase in size and move out radially as the heat front produced by heat source 100 moves outward. As the heat front migrates through the formation, hydrocarbons may be pyrolyzed as temperatures within rich zones 122 reach pyrolysis temperatures. Pyrolyzation of the hydrocarbons, along with heating of the rich zones, may increase the permeability of rich zones 122. At later times of heating, hydrocarbons in coking portion 134 of permeable zone 132 may coke as temperatures within this portion increase to coking temperatures. At some point permeable zone 132 will move outward to a distance from opening 126 at which no coking of hydrocarbons occurs (i. e. , a distance at which temperatures do not approach coking temperatures). Permeable zone 132 may continue to expand with the migration of the heat front through the formation. If sufficient water is present, coking may be suppressed near opening 126.

In certain embodiments, fluids formed in rich zones 122 may flow into lean zones 120 through permeable zone 132. Coking portion 134 may inhibit the flow of fluids between rich zones 122 and lean zones 120. Fluids may continue to flow into lean zones 120 through un-coked portions of permeable zone 132. In some embodiments, fluids may flow to opening 126 (e. g. , during early times of heating before permeable zone 132 has sufficient permeability for fluid flow into the lean zones). Fluids that flow to opening 126may be produced through the opening or be allowed to flow through lean zones 120 to production well 104. In addition, during early times of heating, some coke formation may occur near opening 126.

Allowing formation fluids to be produced through lean zones 120 may allow for earlier production of fluids formed in rich zones 122. For example, fluids formed in rich zones 122 may be produced through lean zones 120 before sufficient permeability has been created in the rich zones for fluids to flow directly within the rich zones to production well 104. Producing at least some fluids through lean zone 120 or through opening 126 may inhibit a buildup of pressure within the formation during heating of the formation.

In certain embodiments, fractures 130 may propagate in a horizontal direction. However, fractures 130 may propagate in other directions depending on, for example, a depth of the fracuring layer and structure of the fracturing layer. As an example, oil shale formations in the Piceance basin in Colorado that are deeper than about 125 m below the surface tend to have fractures that propagate at an angle or vertically. In certain embodiments, the creation of angled or vertical fractures may be inhibited to inhibit fracturing into an aquifer or other environmentally sensitive area.

In some embodiments, applying heat to rich zones 122 may create fractures within the rich zones.

Fractures within rich zone 122 may be less likely to initially occur due to the more ductile (less brittle) composition of the rich zone as compared to lean zones 120. In an embodiment, fractures may develop that connect lean zones 120 and rich zones 122. These fractures may provide a path for propagation of fluids from one zone to the other zone.

Production well 104 may be placed at an angle, vertically, or horizontally into lean zones 120 and rich zones 122. Production well 104 may produce formation fluids from lean zones 120 and/or rich zones 122.

In some embodiments, more than one production well may be placed in lean zones 120 and/or rich zones 122. A number of production wells may be determined by, for example, a desired product quality of the produced fluids, a desired production rate, a desired weight percentage of a component in the produced fluids, etc.

In other embodiments, formation fluids may be produced through opening 126, which may be uncased or perforated. Producing formation fluids through opening 126 tends to increase cracking of hydrocarbons (from the heat provided by heat source 100) as the fluids propagate along the length of the opening. Fluids produced through opening 126 may have lower carbon numbers than fluids produced through production well 104.

In an in situ conversion process embodiment, pressure may be increased within a selected section of a portion of a hydrocarbon containing formation to a selected pressure during pyrolysis. A selected pressure may be within a range from about 2 bars absolute to about 72 bars absolute or, in some embodiments, 2 bars absolute to 36 bars absolute. Alternatively, a selected pressure may be within a range from about 2 bars absolute to about 18 bars absolute. In some in situ conversion process embodiments, a majority of hydrocarbon fluids may be produced from a formation having a pressure within a range from about 2 bars absolute to about 18 bars absolute. The pressure during pyrolysis may vary or be varied. The pressure may be varied to alter and/or control a composition of a formation fluid produced, to control a percentage of condensable fluid as compared to non-condensable fluid, and/or to control an API gravity of fluid being produced. For example, decreasing pressure may result in production of a larger condensable fluid component. The condensable fluid component may contain a larger percentage of olefins.

Operating an in situ conversion process at increased pressure may allow for vapor phase production of formation fluid from the formation. Vapor phase production may permit increased recovery of lighter (and relatively high quality) pyrolyzation fluids. Vapor phase production may result in less formation fluid being left in the formation after the fluid is produced by pyrolysis. Vapor phase production may allow for fewer production wells in the formation than are present using liquid phase or liquid/vapor phase production. Fewer production wells may significantly reduce equipment costs associated with an in situ conversion process.

In an embodiment, a portion of a hydrocarbon containing formation may be heated to increase a partial pressure of H2. In some embodiments, an increased H2 partial pressure may include H2 partial pressures in a range from about 0.5 bars to about 7 bars. Alternatively, an increased H2 partial pressure range may include H2 partial pressures in a range from about 5 bars to about 7 bars. For example, a majority of hydrocarbon fluids may be produced wherein a H2 partial pressure is within a range of about 5 bars to about 7 bars. A range of H2 partial pressures within the pyrolysis H2 partial pressure range may vary depending on, for example, temperature and pressure of the heated portion of the formation.

Maintaining a H2 partial pressure within the formation of greater than atmospheric pressure may increase an API value of produced condensable hydrocarbon fluids. Maintaining an increased H2 partial pressure may increase an API value of produced condensable hydrocarbon fluids to greater than about 25° or, in some instances,

greater than about 30°. Maintaining an increased H2 partial pressure within a heated portion of a hydrocarbon containing formation may increase a concentration of H2 within the heated portion. The H2 may be available to react with pyrolyzed components of the hydrocarbons. Reaction of H2 with the pyrolyzed components of hydrocarbons may reduce polymerization of olefins into tars and other cross-linked, difficult to upgrade, products.

Therefore, production of hydrocarbon fluids having low API gravity values may be inhibited.

Further modifications and alternative embodiments of various aspects of the invention may be apparent to those skilled in the art in view of this description. Accordingly, this description is to be construed as illustrative only and is for the purpose of teaching those skilled in the art the general manner of carrying out the invention. It is to be understood that the forms of the invention shown and described herein are to be taken as the presently preferred embodiments. Elements and materials may be substituted for those illustrated and described herein, parts and processes may be reversed, and certain features of the invention may be utilized independently, all as would be apparent to one skilled in the art after having the benefit of this description of the invention. Changes may be made in the elements described herein without departing from the spirit and scope of the invention as described in the following claims. In addition, it is to be understood that features described herein independently may, in certain embodiments, be combined.