PRODUCING HYDROCARBONS AND NON-HYDROCARBON CONTAINING MATERIALS FROM A HYDROCARBON CONTAINING FORMATION BACKGROUND OF THE INVENTION 1. Field of the Invention The present invention relates generally to methods and systems for producing hydrocarbons and non- hydrocarbon materials from a hydrocarbon containing formation. The present invention also generally relates to producing non-hydrocarbon materials from a formation prior to hydrocarbon material production to reduce generation of carbon dioxide, to increase permeability, to increase porosity, and/or to improve heat transfer characteristics in the formation 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.

There has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, minerals, metals and/or other economically viable materials from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which minerals, metals and/or other economically viable materials cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, metals and/or other economically viable materials from various hydrocarbon containing formations.

SUMMARY OF THE INVENTION Hydrocarbons within a hydrocarbon containing formation (e. g. , a formation containing coal, oil shale, heavy hydrocarbons, or combinations 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 some in situ conversion process embodiments, non-hydrocarbon materials such as minerals, metals, and other economically viable materials contained within the formation may be economically produced from the formation. In certain embodiments, non-hydrocarbon materials may be recovered and/or produced prior to, during, and/or after the in situ conversion process for treating hydrocarbons using an additional in situ process of treating the formation for producing the non-hydrocarbon materials.

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 embodiment for solution mining a formation.

FIG. 2 illustrates cumulative oil production and cumulative heat input versus time using an in situ conversion process for solution mined oil shale and for non-solution mined oil shale.

FIG. 3 depicts a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing 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 <BR> <BR> 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 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"includes 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.

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, as described in embodiments herein. 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, as described in embodiments herein. In addition, it is envisioned that in some embodiments heat provided to or generated in one or more heat sources may be supplied be 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 <BR> <BR> may provide heat from one or more other energy sources (e. g. , chemical reactions, solar energy, wind energy,<BR> 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 <BR> <BR> 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 <BR> <BR> "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 <BR> <BR> be considered pyrolyzation fluid or pyrolyzation product. As used herein, "pyrolysis zone"refers to a volume of a<BR> formation (e. g. , a relatively permeable formation such as a tar sands formation) that is reacted or reacting to form a pyrolyzation fluid.

In some in situ conversion process embodiments, non-hydrocarbon materials such as minerals, metals, and other economically viable materials contained within a hydrocarbon containing formation may be economically

produced from the formation using an in situ conversion process for non-hydrocarbon materials. Non-hydrocarbon materials may be recovered and/or produced prior to, during, and/or after an in situ conversion process for treating hydrocarbons. In certain embodiments, the non-hydrocarbon materials may be mined or extracted from the formation following an in situ conversion process. However, mining or extracting material following an in situ conversion process may not be economically or environmentally favorable.

In an embodiment for producing non-hydrocarbon material, a portion of the formation may be subjected to in situ conversion process to produce hydrocarbons and/or synthesis gas from the formation. The temperature of <BR> <BR> the portion may be reduced below the boiling point of water at formation conditions. A first fluid (e. g. , extraction fluid) may be injected into the portion. The first fluid may be injected through a production well, heater well, or injection well. The first fluid may include an agent that reduces, mixes, combines, or forms a solution with non- hydrocarbon materials to be recovered. The first fluid may be water, a basic solution, an acid solution, and/or a hydrocarbon fluid. In some embodiments, the first fluid may be introduced into the formation as a hot or warm liquid. The first fluid may be heated using heat generated in another portion of the formation and/or using excess heat from another portion of the formation.

A second fluid may be produced in the formation from formation material and the first fluid. The second fluid may be produced from the formation through production wells. The second fluid may include desired non- hydrocarbon materials from the formation. The non-hydrocarbon materials may include valuable metals such as, but not limited to, aluminum, nickel, vanadium, and gold. The non-hydrocarbon materials may also include minerals that contain phosphorus, sodium, or magnesium. In certain embodiments, the second fluid may include metals combined with minerals. For example, the second fluid may contain phosphates, carbonates, etc. Metals, minerals, or other non-hydrocarbon materials contained within the second fluid may be produced or extracted from the second fluid.

Producing the non-hydrocarbon materials may include separating the materials from the solution mixture.

Producing the non-hydrocarbon materials may include processing the second fluid in a surface facility or refinery.

In some embodiments, the first fluid may be circulated through the formation from an injection well to a removal site of the second fluid. Any portion of the first fluid remaining in the second fluid may be recirculated (or re- injected) into the formation as a portion of the first fluid. In other embodiments, the second fluid may be treated at the surface to remove non-hydrocarbon materials from the second fluid. This may reconstitute the first fluid from the second fluid. The reconstituted first fluid may be re-injected into the formation for further material recovery.

In certain embodiments (e. g. , in a coal formation), a first fluid may be injected into a portion of the formation that has been treated using an in situ conversion process. The first fluid may include water. The first fluid may break and/or fragment the formation into relatively small pieces of mineral matrix containing hydrocarbons. The relatively small pieces may combine with the first fluid to form a slurry. The slurry may be removed or produced from the formation. The slurry may be treated in a surface facility to separate the first fluid from the relatively small pieces of hydrocarbons. The mineral matrix containing hydrocarbon pieces may be treated in a refining or extraction process in a surface facility. The mineral matrix containing hydrocarbon pieces may be an anthracite form of coal.

In some embodiments, non-hydrocarbon materials may be produced from a formation prior to treating the formation in situ. Heat may be provided to the formation from heat sources. The formation may reach an average <BR> <BR> temperature approaching below pyrolysis temperatures (e. g. , about 260 °C or less). A first fluid may be injected

into the formation. The first fluid may dissolve and or entrain formation material to form a second fluid. The second fluid may be produced from the formation.

Some hydrocarbon containing formations (such as oil shale) may include nahcolite, trona, and/or dawsonite within the formation. For example, nahcolite may be contained in unleached portions of a formation.

Unleached portions of a formation are parts of the formation where groundwater has not leached out minerals within the formation. For example, in the Piceance basin in Colorado, unleached oil shale is found below a depth of about 500 m below grade. Deep unleached oil shale formations in the Piceance basin center tend to be rich in hydrocarbons. For example, about 0.10 liters of oil per kilogram (L/kg) of oil shale to about 0.15 L/kg of oil shale may be producible from an unleached oil shale formation.

Nahcolite is a mineral that includes sodium bicarbonate (NaHCO3). Greater than about 5 weight %, and in some embodiments even greater than about 10 weight %, or greater than about 20 weight % nahcolite may be present in a formation. Dawsonite is a mineral that includes sodium aluminum carbonate (NaAI (CO3) (OH) 2).

Dawsonite may be present in a formation at weight percents greater than about 2 weight % or, in some embodiments, greater than about 5 weight %. The nahcolite and/or dawsonite may dissociate at temperatures used in an in situ conversion process of treating a formation. The dissociation is strongly endothermic and may produce large amounts of carbon dioxide. The nahcolite and/or dawsonite may be solution mined prior to, during, and/or following treating a formation in situ to avoid the dissociation reactions. For example, hot water may be used to form a solution with nahcolite. Nahcolite may form sodium ions (Na) and bicarbonate ions (HC03) in aqueous solution. The solution may be produced from the formation through production wells.

A formation that includes nahcolite and/or dawsonite may be treated using an in situ conversion process.

A perimeter barrier may be formed around the portion of the formation to be treated. In some embodiments, <BR> <BR> 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.

FIG. 1 depicts an embodiment for solution mining a formation. Barrier 100 (e. g. , a frozen barrier) may be formed around a circumference of treatment area 102 of the formation. Barrier 100 may be any barrier formed to inhibit a flow of water into or out of treatment area 102. For example, barrier 100 may include one or more freeze wells that inhibit a flow of water through the barrier. In some embodiments, barrier 100 has a diameter of about 18 m. Barrier 100 may be formed using one or more barrier wells 104. Barrier wells 104 may have a spacing of about 2.4 m. Formation of barrier 100 may be monitored using monitor wells 106 and/or by monitoring devices placed in barrier wells 104.

Water inside treatment area 102 may be pumped out of the treatment area through production well 108.

Water may be pumped until a production rate of water is low. Heat may be provided to treatment area 102 through heat sources 110. The provided heat may heat treatment area 102 to a temperature of about 90 °C or, in some embodiments, to a temperature of about 100 °C, 110 °C, or 120 °C. A temperature of treatment area 102 may be monitored using temperature measurement devices placed in temperature wells 112.

A first fluid (e. g. , water) may be injected through one or more injection wells 114. The first fluid may also be injected through a heater or production well located in the formation. The first fluid may mix and/or combine

with non-hydrocarbon materials (e. g. , minerals, metals, nahcolite, and dawsonite) that are soluble in the first fluid to produce a second fluid. The second fluid, containing the non-hydrocarbon materials, may be removed from the treatment area through production well 108 and/or heat sources 110. Production well 108 and heat sources 110 may be heated during removal of the second fluid. After producing a majority of the non-hydrocarbon materials from treatment area 102, solution remaining within the treatment area may be removed (e. g. , by pumping) from the treatment area through production well 108 and/or heat sources 110. A relatively high permeability treatment area 102 may be produced following removal of the non-hydrocarbon materials from the treatment area.

Hydrocarbons within treatment area 102 may be pyrolyzed and/or produced using an in situ conversion process of treating a formation following removal of the non-hydrocarbon materials. Heat may be provided to treatment area 102 through heat sources 110. A mixture of hydrocarbons may be produced from the formation through production well 108 and/or heat sources 110.

In certain embodiments, during an initial heating up to a temperature near a boiling temperature of water, unleached soluble minerals within the formation may be disaggregated and dissolved in water condensing within the formation. The water may be condensing in cooler portions of the formation. Some of these minerals may flow in the condensed water to production wells. The water and minerals are produced through the production wells.

In alternate embodiments, a formation may be solution mined after an in situ conversion process for hydrocarbons. Following the in situ conversion process, treatment area 102 may be cooled during heat recovery by introduction of water to produce steam from a hot portion of the formation. Introduction of water to produce steam may vaporize some hydrocarbons remaining in the formation. Water may be injected through injection wells 114.

The injected water may cool the formation. The remaining hydrocarbons and generated steam may be produced through production wells 108 and/or heater wells 110. Treatment area 102 may be cooled to a temperature near the boiling point of water.

Treatment area 102 may be further cooled to a temperature at which water will begin to condense within <BR> <BR> the formation (i. e. , a temperature below a boiling temperature of water). Removing the water or other solvents from treatment area 102 may also remove any materials remaining in the treatment area that are soluble in water. The water may be pumped out of treatment area 102 through production well 108 and/or heater wells 110. Additional water and/or other solvents may be injected into treatment area 102. This injection and removal of water may be repeated until a sufficient water quality within treatment area 102 is reached. Water quality may be measured at injection wells 114, heater wells 110, and/or production wells 108. The sufficient water quality may be a water quality that substantially matches a water quality of treatment area 102 prior to treatment.

In some embodiments, treatment area 102 may include a leached zone located above an unleached zone.

The leached zone may have been leached naturally and/or by a separate leaching process. In certain embodiments, the unleached zone may be at a depth of about 500 m. A thickness of the unleached zone may be about 100 m to about 500 m. However, the depth and thickness of the unleached zone may vary depending on, for example, a location of treatment area 102 and a type of formation. A first fluid may be injected into the unleached zone below the leached zone. Heat may also be provided into the unleached zone.

In certain embodiments, a section of a formation may be left unleached or without injection of a solution.

The unleached section may be proximate a selected section of the formation that has been leached by providing a first fluid as described above. The unleached section may inhibit the flow of water into the selected section. In some embodiments, more than one unleached section may be proximate a selected section.

In an embodiment, a formation may contain both nahcolite and/or dawsonite. Nahcolite, hydrocarbons, and alumina (from dawsonite) may be produced from these types of formations.

Water may be injected into the formation through a heater well or an injection well. The water may be heated and/or injected as steam. The water may be injected at a temperature at or near the decomposition temperature of nahcolite. For example, the water may be at a temperature of about 70 °C, 90 °C, 100 °C, or 110 °C.

Nahcolite within the formation may form an aqueous solution following the injection of water. The aqueous solution may be removed from the formation through a heater well, injection well, or production well. Removing the nahcolite removes material that would otherwise form carbon dioxide during heating of the formation to pyrolysis temperature. Removing the nahcolite may also inhibit the endothermic dissociation of nahcolite during an in situ conversion process. Removing the nahcolite may reduce mass within the formation and increase a permeability of the formation. Reducing the mass within the formation may reduce the heat required to heat to temperatures needed for the in situ conversion process. Reducing the mass within the formation may also increase a speed at which a heat front within the formation moves. Increasing the speed of the heat front may reduce a time needed for production to begin. In some embodiments, slightly higher temperatures may be used in the formation (e. g. , above about 120 °C) and the nahcolite may begin to decompose. In such a case, nahcolite may be removed from the formation as a soda ash (Na2CO3).

Nahcolite removed from the formation may be heated in a surface facility to form sodium carbonate and/or sodium carbonate brine. Heating nahcolite will form sodium carbonate according to the equation: (1) 2NaHCO3-> Na2C03 + CO2 + : HZO.

The sodium carbonate brine may be used to solution mine alumina. The carbon dioxide produced may be used to precipitate alumina. If soda ash is produced from solution mining of nahcolite, the soda ash may be transported to a separate facility for treatment. The soda ash may be transported through a pipeline to the separate facility.

Following removal of nahcolite from the formation, the formation may be treated using an in situ conversion process to produce hydrocarbon fluids from the formation. Remaining water is drained from the solution mining area through dewatering wells prior to heating to in situ conversion process temperatures. During the in situ conversion process, a portion of the dawsonite within the formation may decompose. Dawsonite will typically decompose at temperatures above about 270 °C according to the reaction: (2) 2NaA1 (OH) 2C03- NaCOs + A1203 + 2H20 + CO2.

The alumina formed from EQN. 2 will tend to be in the form of chi alumina. Chi alumina is relatively soluble in basic fluids.

Alumina within the formation may be solution mined using a relatively basic fluid following reaching pyrolysis temperatures of hydrocarbons within the formation. For example, a dilute sodium carbonate brine, such as 0.5 Normal Na2CO3, may be used to solution mine alumina. The sodium carbonate brine may be obtained from solution mining the nahcolite. Obtaining the basic fluid by solution mining the nahcolite may significantly reduce costs associated with obtaining the basic fluid. The basic fluid may be injected into the formation through a heater well and/or an injection well. The basic fluid may form an alumina solution that may be removed from the

formation. The alumina solution may be removed through a heater well, injection well, or production well. An excess of basic fluid may have to be maintained throughout an alumina solution mining process.

Alumina may be extracted from the alumina solution in a surface facility. In an embodiment, carbon dioxide may be bubbled through the alumina solution to precipitate the alumina from the basic fluid. Carbon dioxide may be obtained from the in situ conversion process or from decomposition of the dawsonite during the in situ conversion process.

In certain embodiments, a formation may include portions that are significantly rich in either nahcolite or <BR> <BR> dawsonite only. For example, a formation may contain significant amounts of nahcolite (e. g. , greater than about 20 weight %) in a depocenter of the formation. The depocenter may contain only about 5 weight % or less dawsonite on average. However, in bottom layers of the formation, a weight percent of dawsonite may be about 10 weight % or even as high as about 25 weight %. In such formations, it may be advantageous to solution mine for nahcolite only in nahcolite-rich areas, such as the depocenter, and solution mine for dawsonite only in the dawsonite-rich areas, such as the bottom layers. This selective solution mining may significantly reduce a fluid cost, heating cost, and/or equipment cost associated with operating a solution mining process.

Nordstrandite (Al (OH) 3) is another aluminum bearing mineral that may be found in a formation.

Nordstrandite decomposes at about the same temperatures (about 300 °C) as dawsonite and will produce alumina according to the equation: (3) 2AI (OH) 3-> A1203 + 3H2O.

Nordstrandite is typically found in formations that also contain dawsonite and may be solution mined simultaneously with the dawsonite.

Solution mining dawsonite and nahcolite may be a simple process that produces only aluminum and soda ash from a formation. It may be possible to use some or all hydrocarbons produced from an in situ conversion process to produce direct current (DC) electricity on a site of the formation. The produced DC electricity may be used on the site to produce aluminum metal from the alumina using the Hall process. Aluminum metal may be produced from the alumina by melting the alumina in a surface facility on the site. Generating the DC electricity at the site may save on costs associated with using hydrotreaters, pipelines, or other surface facilities associated with transporting and/or treating hydrocarbons produced from the formation using the in situ conversion process.

Some formations may also contain amounts of trona. Trona is a sodium sesquicarbonate (Na2CO3 NaHCO3 2H20) that has properties and undergoes reactions (including decomposition) very similar to those of nahcolite. Treatments for solution mining of trona may be substantially similar to treatments used for solution mining of nahcolite. Trona may typically be found in kerogen formations such as oil shale formations in Wyoming.

For certain types of formations, solution mining may be used to recover non-hydrocarbon materials prior- to heating the formation to hydrocarbon pyrolysis temperatures. Examples of such materials and formations may include nahcolite and dawsonite in Green River oil shale, trona in Wyoming oil shale, or ammonia from buddingtonite in the Condor deposit in Queensland, Australia. Other non-hydrocarbon materials that may be solution mined include carbonates (e. g. , trona, eitelite, burbankite, shortite, pirssonite, gaylussite, norsethite,<BR> thermonatrite), phosphates, carbonate-phosphates (e. g. , bradleyite), carbonate chlorides (e. g. , northupite), silicates<BR> (e. g. , albite, analcite, sepiolite, loughlinite, labuntsovite, acmite, elpidite, magnesioriebeckite, feldspar),

borosilicates (e. g. , reedmergnerite, searlesite, leucosphenite), and halides (e. g. , neighborite, cryolite, halite).

Solution mining prior to hydrocarbon pyrolysis may increase a permeability of the formation and/or improve other features (e. g. , porosity) of the formation for the in situ process. Solution mining may also remove significant portions of compounds that will tend to endothermically dissociate at increased temperatures. Removing these endothermically dissociating compounds from the formation tends to decrease an amount of heat input required to heat the formation.

For some types of formations, it may be advantageous to solution mine a formation after pyrolysis and/or synthesis gas production. Many different types of non-hydrocarbon materials may be removed from a formation following an in situ conversion process.

For example, phosphate may be removed from marine oil shale formations such as the Phosphoria formation in Idaho. Phosphate may have a weight percentage up to about 20 weight % or about 30 weight % in these formations. Recovered phosphate may be used in combination with ammonia and/or sulfur produced during the in situ conversion process to produce useable materials such as fertilizer.

Metals may also be recoverable from marine oil shale deposits. Metals such as uranium, chromium, cobalt, nickel, gold, zinc, etc. may be recovered from marine oil shale formations. Metals may also be found in certain bitumen deposits. For example, bitumen deposits may contain amounts of vanadium, nickel, uranium, platinum, or gold.

A simulation was used to predict the effects of solution mining nahcolite and dawsonite from an oil shale formation. The simulation predicts the effect on oil production and energy requirements for producing hydrocarbons from the oil shale formation using an in situ conversion process. The kinetics of decomposition of nahcolite and dawsonite were used in the simulation.

Nahcolite decomposed into soda ash, carbon dioxide, and water. The frequency factor for the decomposition was 7.83 x 10l5 (L/days). The activation energy was 1.015 x 105 joules per gram mole (J/gmol).

The heat of reaction was-62,072 J/gmol.

Dawsonite decomposed into soda ash plus alumina (AI203), carbon dioxide, and water. The frequency factor for the decomposition was 1.0 x 102° (L/days). The activation energy was 2.039 x 105 J/gmol. The heat of reaction was-151,084 J/gmol.

The simulation assumed a 12.2 m well spacing in a triangular pattern. An injector well to producer well ratio was 12 to 1. FIG. 2 illustrates cumulative oil production (m3) and cumulative heat input (kilojoules) versus time (years) using an in situ conversion process for solution mined oil shale and for pre-solution mined oil shale.

Curve 112 illustrates cumulative oil production for non-solution mined oil shale. Curve 114 illustrates cumulative heat input for non-solution mined oil shale. Curve 116 illustrates cumulative oil shale production for solution mined oil shale. Curve 118 illustrates cumulative heat input for solution mined oil shale.

The non-solution mined oil shale was assumed to have a 0.125 liters per kilogram (L/kg) Fischer Assay with 5% dawsonite and 20% nahcolite, a 1.9% fracture porosity, and a 65% water saturation. The solution mined oil shale was found to have a 0.125 L/kg Fischer Assay with 5% dawsonite and 0% nahcolite, a 29% porosity (created from removal of the nahcolite), and a 1.5 % water saturation. The solution mined oil shale was assumed to have a relatively high permeability, which reduces the water saturation to 1.5%.

As shown in FIG. 2, the simulation predicts that oil production in solution mined oil shale 116 begins sooner and is faster than oil production in the non-solution mined oil shale 112. For example, after about 9 years, solution mined oil shale has produced about 9500 m3 of oil, while non-solution mined oil shale has only produced

about 1500 m3 of oil. Non-solution mined oil shale will produce about 9500 m3 of oil in about 12 years, 3 years later than solution mined oil shale.

Also, the simulation predicts that less heat is needed to produce oil from solution mined oil shale 118 than from non-solution mined oil shale 114. For example, after about 9 years, solution mined oil shale has required about 9 x 1 ol° kJ of heat input, while non-solution mined oil shale has required about 1.1 x 10"kJ of heat input. <BR> <P>In certain embodiments a soluble compound (e. g. , phosphates, bicarbonates, alumina, metals, minerals,<BR> etc. ) may be produced from a soluble compound containing formation (e. g. , a formation that contains nahcolite, dawsonite, nordstrandite, trona, carbonates, carbonate-phosphates, carbonate chlorides, silicates, borosililcates, etc.) that is different from a hydrocarbon containing formation. For example, the soluble compound containing formation may be adjacent (e. g. , lower or higher than) the hydrocarbon containing formation, or at different non- adjacent depths than the hydrocarbon containing formation. In other embodiments, the soluble compound containing formation may be located at a different geographic location than the hydrocarbon containing formation.

In an embodiment, heat is provided from one or more heat sources to at least a portion of a hydrocarbon containing formation. A mixture, at some point, may be produced from the formation. The mixture may include hydrocarbons from the formation as well as other compounds such as CO2, H2, etc. Heat from the formation, or heat from the mixture produced from the formation, may be used to adjust or change a quality of a first fluid that is provided to the soluble compound containing formation. Heat may be provided in the form of hot water or steam produced from the formation. In other embodiments, heat may be transferred by heat exchangers to the first fluid.

In other embodiments, a heated portion or component from the mixture may be mixed with the first fluid to heat the fluid.

Alternately, or in addition, a component from the mixture produced from the hydrocarbon containing formation may be used to adjust a quality of a first fluid. For example, acidic compounds (e. g. , carbonic acid,<BR> organic acids) or basic compounds (e. g. , ammonium, carbonate, or hydroxide compounds) from the mixture produced from the hydrocarbon containing formation may be used to adjust the pH of the first fluid. For example, CO2 from the hydrocarbon containing formation may be used with water to acidify the first fluid. In certain embodiments, components added to the first fluid (e. g. , divalent cations, pyridines, or organic acids such as carboxylic acids or naphthenic acids) may increase the solubility of the soluble compound in the first fluid.

Once adjusted (e. g. , heated and/or changed by having at least one component added to the first fluid), the first fluid may be injected into the soluble compound containing formation. The first fluid may, in some embodiments, include hot water or steam. The first fluid may interact with the soluble compound. The soluble compound may at least partially dissolve. A second fluid including the soluble compound may be produced from the soluble compound containing formation. The soluble compound may be separated from the second fluid stream and treated or processed. Portions of the second fluid may be recycled into the formation.

In certain embodiments, heat from the hydrocarbon containing formation may migrate and heat at least a portion of the soluble compound containing formation. In some embodiments, the soluble compound containing formation may be substantially near, adjacent to, or intermixed with the hydrocarbon containing formation. The heat that migrates may be useful to enhance the solubility of the soluble compound when the first fluid is applied to the soluble compound containing formation. Heat that migrates from the hydrocarbon containing formation may be recovered instead of being lost.

Reusing openings (wellbores) for different applications may be cost effective in certain embodiments. In some embodiments, openings used for providing the heat sources (or from producing from the hydrocarbon

containing formation) may be used to provide the first fluid to the soluble compound containing formation or to produce the second fluid from the soluble compound containing formation.

In certain embodiments, a solution may be first provided to, or produced from, a formation in a solution mining operation. The solution may be provided or produced through openings. One or more of the same openings may later be used as heater wells or producer wells for an in situ conversion process. Additionally, one or more of the same openings may be used again for providing a first fluid to the same formation layer or to a different formation layer. For example, the openings may be used to solution mine components such as nahcolite. These openings may further be used as heater wells or producer wells in the hydrocarbon containing formation. Then the openings may be used to provide the first fluid to either the hydrocarbon containing layer or a different layer at a different depth than the hydrocarbon containing layer. These openings may also be used when producing second fluid from the solution compound containing formation.

FIG. 3 shows a schematic view of an embodiment of a portion of an in situ conversion system for treating a hydrocarbon containing formation. Heat sources 110 may be placed within at least a portion of the hydrocarbon containing formation. Heat sources 110 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 110 may also include other types of heaters. Heat sources 110 may provide heat to at least a portion of a hydrocarbon containing formation. Energy may be supplied to the heat sources 110 through supply lines 120. 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 108 may be used to remove formation fluid from the formation. Formation fluid produced from production wells 108 may be transported through collection piping 122 to treatment facilities 124.

Formation fluids may also be produced from heat sources 110. For example, fluid may be produced from heat sources 110 to control pressure within the formation adjacent to the heat sources. Fluid produced from heat sources 110 may be transported through tubing or piping to collection piping 122 or the produced fluid may be transported through tubing or piping directly to treatment facilities 124. Treatment facilities 124 may include separation units, reaction units, upgrading units, fuel cells, turbines, storage vessels, and other systems and units for processing produced formation fluids. An in situ conversion system for treating hydrocarbons may include barrier wells 104.

Barrier wells 104 may, in some embodiments, be capture wells, dewatering wells, freeze wells, and/or isolation wells.

A pattern of heat sources will often include many units of heat sources. There will typically be many heated portions, as well as many selected sections within the pattern of heat sources. Heat may be allowed to transfer from one or more of the heat sources to part of the formation substantially by conduction. 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.

As shown in FIG. 3, in addition to heat sources 110, one or more production wells 108 will typically be placed within the portion of the hydrocarbon containing formation. Formation fluids may be produced through

production well 108. In some embodiments, production well 108 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.

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.

Embodiments of a production well may include valves that alter, maintain, and/or control a pressure of at least a portion of the formation. Production wells may be cased wells. Production wells may have production screens or perforated casings adjacent to production zones. In addition, the production wells may be surrounded by sand, gravel or other packing materials adjacent to production zones. Production wells 108 may be coupled to treatment facilities 124, as shown in FIG. 3.

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.

Triangular patterns tend to provide more uniform heating to a portion of the formation in comparison to other patterns such as squares and/or hexagons. Triangular patterns tend to provide faster heating to a predetermined temperature in comparison to other patterns such as squares or hexagons. The use of triangular patterns may result in smaller volumes of a formation being overheated. A plurality of units of heat sources, such as a triangular pattern, may be arranged substantially adjacent to each other to form a repetitive pattern of units over an area of the formation. For example, triangular patterns may be arranged substantially adjacent to each other in a repetitive pattern of units by inverting an orientation of adjacent triangles. Other patterns of heat sources 108 may also be arranged such that smaller patterns may be disposed adjacent to each other to form larger patterns.

Exact placement of heater wells, production wells, etc. will depend on variables specific to the formation (e. g. , thickness of the layer or composition of the layer), project economics, etc. In certain embodiments, heater wells may be substantially horizontal while production wells may be vertical, or vice versa. In some embodiments, wells may be aligned along dip or strike or oriented at an angle between dip and strike.

The spacing between heat sources may vary depending on a number of factors. The factors may include, but are not limited to, the type of a hydrocarbon containing formation, the selected heating rate, and/or the selected average temperature to be obtained within the heated portion. In some well pattern embodiments, the spacing between heat sources may be within a range of about 5 m to about 25 m. In some well pattern embodiments, spacing between heat sources may be within a range of about 8 m to about 15 m.

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 increases, 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 <BR> <BR> 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.

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.

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 olefms.

In some in situ conversion process embodiments, increased pressure due to fluid generation may be maintained within the heated portion of the formation. Maintaining increased pressure within a formation may inhibit formation subsidence during in situ conversion. Increased formation pressure may promote generation of

high quality products during pyrolysis. Increased formation pressure may facilitate vapor phase production of fluids from the formation.

Increased pressure in the formation may also be maintained to produce more and/or improved formation fluids. In certain in situ conversion process embodiments, significant amounts (e. g. , a majority) of the hydrocarbon fluids produced from a formation may be non-condensable hydrocarbons. Pressure may be selectively increased and/or maintained within the formation to promote formation of smaller chain hydrocarbons in the formation.

Producing small chain hydrocarbons in the formation may allow more non-condensable hydrocarbons to be produced from the formation. The condensable hydrocarbons produced from the formation at higher pressure may <BR> <BR> be of a higher quality (e. g. , higher API gravity) than condensable hydrocarbons produced from the formation at a lower pressure.

Maintaining increased pressure within a heated portion of the formation may surprisingly allow for production of large quantities of hydrocarbons of increased quality. Maintaining increased pressure may promote vapor phase transport of pyrolyzation fluids within the formation. Increasing the pressure often permits production of lower molecular weight hydrocarbons since such lower molecular weight hydrocarbons will more readily transport in the vapor phase in the formation.

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.

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.