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, and/or other products from hydrocarbon containing formations. At present, however, there are still many hydrocarbon containing formations from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. There is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various hydrocarbon containing formations.

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 heat sources 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 one embodiment, a method of using a computer system for operating an in situ process for treating a hydrocarbon containing formation may include operating the in situ process using one or more operating parameters. At least one operating parameter of the in situ process may be provided to the computer system. At

least one operating parameter may be used with a simulation method and the computer system to provide assessed information about the in situ process. In some embodiments, the assessed information may be used to operate the in situ process.

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 illustrates a flowchart of an embodiment of a method for modeling an in situ process for treating a hydrocarbon containing formation using a computer system.

FIG. 4 illustrates a model for simulating a heat transfer rate in a formation.

FIG. 5 illustrates a flowchart of an embodiment of a method for design and/or control of an in situ process.

FIG. 6 illustrates a flowchart of an embodiment of a method for modeling deformation due to in situ treatment of a hydrocarbon containing formation.

FIG. 7 illustrates a method for controlling an in situ process using a computer system.

FIG. 8 illustrates a schematic of an embodiment for controlling an in situ process in a formation using a computer simulation method.

FIG. 9 illustrates several ways that information may be transmitted from an in situ process to a remote computer system.

FIG. 10 illustrates a schematic of an embodiment for controlling an in situ process in a formation using information.

FIG. 11 illustrates a schematic of an embodiment for controlling an in situ process in a formation using a simulation method and a computer system.

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 simulating treatment of 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.

Simulation methods on a computer system may be used to model an in situ process for treating a formation. Simulations may determine and/or predict operating conditions (e. g. , pressure, temperature, etc.), products that may be produced from the formation at given operating conditions, and/or product characteristics (e. g. , API gravity, aromatic to paraffin ratio, etc. ) for the process. A formation may be modeled using commercially available simulation programs such as STARS, THERM, FLUENT, CFX, and/or ABAQUS. Results of the simulations may be used to operate an in situ process.

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

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

"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. "Bitumen"is a non-crystalline solid or viscous hydrocarbon material that is substantially soluble in carbon disulfide. "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). 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 some embodiments, heat provided to or generated in one or more heat sources may be supplied by sources of energy that directly or indirectly heat a formation.

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, and/or combinations thereof.

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 that is reacted or reacting to form a pyrolyzation fluid.

"Thermal conductivity"is a property of a material that describes the rate at which heat flows, in steady state, between two surfaces of the material for a given temperature difference between the two surfaces.

"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.

"Heavy hydrocarbons"are viscous hydrocarbon fluids. Heavy hydrocarbons may include highly viscous hydrocarbon fluids such as heavy oil, tar, and/or asphalt. Heavy hydrocarbons may include carbon and hydrogen, as well as smaller concentrations of sulfur, oxygen, nitrogen, and additional elements in trace amounts. Heavy hydrocarbons generally have an API gravity below about 20Heavy oil,"for example, generally has an API gravity of about 10-20°."Tar"may have an API gravity less than 10° and generally has a viscosity greater than about 10,000 centipoise at 15 °C. The specific gravity of tar generally is greater than 1.000. Certain types of formations that include heavy hydrocarbons may also be, but are not limited to, natural mineral waxes, or natural asphaltites.

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. 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. 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.

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.

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, or other temperatures. Energy input from the heat sources may be adjusted to maintain the formation temperature substantially at the desired temperature.

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.

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, 2 bars absolute to 36 bars absolute, or from about 2 bars absolute to about 18 bars absolute.

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 formation, and/or a distance from a producer well. Pressure within a formation may be determined at different locations (e. g. , near or at production wells, near or at heat sources, or at monitoring 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 and/or an open wellbore.

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, from about 2 bars absolute to about 36 bars absolute, or from about 2 bars absolute to about 18 bars absolute. In some embodiments, a majority of hydrocarbon fluids may be produced from a formation having a pressure from about 2 bars absolute to about 18 bars absolute.

Controlling pressure and temperature within a hydrocarbon containing formation may allow properties of the produced formation fluids to be controlled. For example, composition and quality of formation fluids produced from the formation may be altered by altering an average pressure and/or an average temperature in a selected section of a heated portion of the formation.

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 absolute to about 7 bars absolute or from about 5 bars absolute to about 7 bars absolute.

Generation of lower molecular weight hydrocarbons (and corresponding increased vapor phase transport) is believed to be due, in part, to autogenous generation and reaction of hydrogen within a portion of the

hydrocarbon containing formation. For example, maintaining an increased pressure may force hydrogen generated during pyrolysis into a liquid phase (e. g. , by dissolving). H2 in the liquid phase may inhibit the generated pyrolyzation fluids from reacting with each other and/or with other compounds in the formation. Shorter chain hydrocarbons may enter the vapor phase and may be produced from the formation.

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. If a synthesis gas generating fluid is introduced into a formation at a temperature sufficient to allow synthesis gas generation, synthesis gas may be generated within the formation.

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.

Hydrocarbon containing formations may be selected for in situ conversion based on properties of at least a portion of the formation. 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. 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.

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.

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.

In some embodiments, an in situ conversion 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.

During in situ treatment by heating a portion of the formation, permeability and/or porosity of the portion may significantly increase. Because of increased permeability and/or porosity 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. 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.

In an embodiment, a computational system that is suitable for implementing various embodiments of a system and method for in situ processing of a formation typically includes one or more central processing units (CPU) with associated memory mediums, one or more display devices such as a monitor, one or more alphanumeric input devices such as a keyboard, and one or more directional input devices such as a mouse. The memory mediums may store program instructions for computer programs, wherein the program instructions are executable by the CPU. A computational system or computer system is operable to execute the computer programs to implement (e. g. , control, design, simulate, and/or operate) in situ processing of formation systems and methods. In general, the term"computational system"can be broadly defined to encompass any device, or system of devices, having a processor that executes instructions from a memory medium. A CPU executing code and data from the memory medium includes a system/process for creating and executing the software program (s) according to the methods and/or block diagrams described below.

In an embodiment, an in situ conversion process (ICP) may be controlled. An ICP may be controlled using wells placed in the formation, including, but not limited to, barrier wells, monitoring wells, production wells, and/or heater wells. Monitoring wells may be used to monitor subsurface conditions in the formation, such as, but not limited to, pressure, temperature, product quality, and/or fracture progression. Surface data and/or subsurface data may be monitored by instruments placed at each well or certain wells. Surface data may include, but is not limited to, pump status, fluid flow rate, surface pressure/temperature, and heater power. Subsurface data may include, but is not limited to, pressure, temperature, fluid quality, and acoustical sensor data. Surface data and subsurface data may be provided to a computational system. Output from the computational system may include instructions to control one or more conditions of a formation and/or to adjust one or more parameters of the ICP. In addition, remote input data may also be provided to a computational system to control conditions within formation.

Monitored conditions in an ICP may be used in a feedback control process, feedforward control process, or other type of control process.

FIG. 3 illustrates a flowchart of an embodiment of method 112 for modeling an in situ process for treating a hydrocarbon containing formation using a computer system. Method 112 may include providing at least one property 114 of the formation to the computer system. Properties of the formation may include, but are not limited to, porosity, permeability, saturation, thermal conductivity, volumetric heat capacity, compressibility, composition, and number and types of phases in the formation. Properties may also include chemical components, chemical reactions, and kinetic parameters. At least one operating condition 116 of the process may also be provided to the computer system. For instance, operating conditions may include, but are not limited to,

thickness and area of heated portion of the formation, pressure, temperature, heating rate, heat input rate, process time, production rate, time to obtain a given production rate, weight percentage of gases, and/or peripheral water recovery or injection. Operating conditions may also include characteristics of the well pattern such as producer well location, producer well orientation, ratio of producer wells to heater wells, heater well spacing, type of heater well pattern, heater well orientation, and/or distance between an overburden and horizontal heater wells.

A method may include assessing at least one process characteristic 118 of the in situ process using simulation method 120 on the computer system. At least one process characteristic may be assessed as a function of time from at least one property of the formation and at least one operating condition. Process characteristics may include properties of a produced fluid such as API gravity, olefin content, carbon number distribution, ethene to ethane ratio, atomic carbon to hydrogen ratio, and ratio of non condensable hydrocarbons to condensable hydrocarbons (gas/oil ratio). Process characteristics may also include a pressure and temperature in the formation, total mass recovery from the formation, and/or production rate of fluid produced from the formation.

In some embodiments, simulation method 120 may include a numerical simulation method used/performed on the computer system. The numerical simulation method may employ finite difference methods to solve fluid mechanics, heat transfer, and chemical reaction equations as a function of time. A finite difference method may use a body-fitted grid system with unstructured grids to model a formation. An unstructured grid employs a wide variety of shapes to model a formation geometry, in contrast to a structured grid.

In an embodiment, a body-fitted finite difference simulation method may be well suited for simulating systems that include sharp interfaces in physical properties or conditions. A body-fitted finite difference simulation method may be more accurate, in certain circumstances, than space-fitted methods due to the use of fmer, unstructured grids in body-fitted methods. For instance, one such circumstance includes calculation of heat transfer in a heater well and in the region near or close to a heater well, i. e. , a"near wellbore region.". A body-fitted finite difference simulation method may calculate the heat input rate corresponding to a given temperature in a heater well and the temperature distributions both inside the wellbore and at the near wellbore region. CFX, supplied by AEA Technologies in the United Kingdom, is an example of a commercially available body-fitted finite difference simulation method. FLUENT is another commercially available body-fitted finite difference simulation method from FLUENT, Inc. located in Lebanon, New Hampshire.

In an embodiment, the simulation method may include a numerical simulation method on a computer system that uses a space-fitted finite difference method with structured grids. The space-fitted finite difference simulation method may be a reservoir simulation method. A reservoir simulation method may calculate, but is not limited to calculating, fluid mechanics, mass balances, heat transfer, and/or kinetics in the formation. A reservoir simulation method may be particularly useful for modeling multiphase porous media in which convection is a relatively important mechanism of heat transfer. STARS is an example of a reservoir simulation method provided by Computer Modeling Group, Ltd. of Alberta, Canada. STARS may simulate a formation using a combination of structured space-fitted grids and unstructured body-fitted grids. Additionally, THERM is an example of a reservoir simulation method provided by Scientific Software Intercomp.

In certain embodiments, a simulation method may use properties of a formation. In general, the properties of a formation for a model of an in situ process depend on the type of formation. In a model of an oil shale formation, for example, a porosity value may be used to model an amount of kerogen and hydrated mineral matter

't in the formation. The kerogen and hydrated mineral matter used in a model may be determined or approximated by the amount of kerogen and hydrated mineral matter necessary to generate the oil, gas and water produced in laboratory experiments. The remainder of the volume of the oil shale may be modeled as inert mineral matter, which may be assumed to remain intact at all simulated temperatures. In addition, kerogen pyrolyzes during the simulation to produce hydrocarbons and other compounds resulting in a rise in fluid porosity. In some embodiments, the change in porosity during a simulation may be determined by monitoring the amount of solids that are treated/transformed, and fluids that are generated.

In an embodiment of a coal formation model, the amount of coal in the formation for the model may be determined by laboratory pyrolysis experiments. Laboratory pyrolysis experiments may determine the amount of coal in an actual formation. The remainder of the volume may be modeled as inert mineral matter or ash. In some embodiments, the porosity of the ash may be between approximately 5% and approximately 10%.

Absorbed and/or adsorbed fluid components, such as initial moisture, may be modeled as part of a solid phase.

An embodiment of a model of a tar sands formation may include an inert mineral matter phase and a fluid phase that includes heavy hydrocarbons. In an embodiment, the porosity of a tar sands formation may be modeled as a function of the pressure of the formation and its mechanical properties. For example, the porosity,, at a pressure, P, in a tar sands formation may be given by EQN. 1 : (1) #= #refexp[c(P - Pref)] where P,, f is a reference pressure, lp, eflS the porosity at the reference pressure, and c is the formation compressibility.

Some embodiments of a simulation method may require an initial permeability of a formation and a relationship for the dependence of permeability on conditions of the formation. An initial permeability of a formation may be determined from experimental measurements of a sample (e. g. , a core sample) of a formation. In some types of formations (e. g. , a coal formation), a ratio of vertical permeability to horizontal permeability may be adjusted to take into consideration cleating in the formation.

In some embodiments, the porosity of a formation may be used to model the change in permeability of the formation during a simulation. In one embodiment, the dependence of porosity on permeability may be described by an analytical relationship. For example, a Carman-Kozeny type formula is shown in EQN. 2: (2) K = K0 (#f/#f,0)CKpower[(1 - #f,0)/(1 - #f)]2 , o is the initial fluid porosity, Ko is the permeability at initial fluid porosity, and CKpower is a user-defined exponent. The value of CKpower may be fitted by matching or approximating the pressure gradient in an experiment in a formation.

In some formations, such as a tar sands formation, the porosity may take the form: (3) K(#f) = K0 # exp[kmul # (#f - #f,0)/(1 - #f,0)]

where Ko and q0 are the initial permeability and porosity, and k"",, is a user-defined grid dependent permeability multiplier. In other embodiments, a tabular relationship rather than an analytical expression may be used to model the dependence of permeability on porosity.

In certain embodiments, the thermal conductivity of a model of a formation may be expressed in terms of the thermal conductivities of constituent materials. For example, the thermal conductivity may be expressed in terms of solid phase components and fluid phase components. The solid phase in oil shale formations and coal formations may be composed of inert mineral matter and organic solid matter. One or more fluid phases in the formations may include, for example, a water phase, an oil phase, and a gas phase. In some embodiments, the dependence of the thermal conductivity on constituent materials in an oil shale formation may be modeled according to EQN. 4: kth(T) = #f # (kth,w # Sw + kth,0 # S0 + kth,g # Sg) + (1 - #) # kth,r(T) + (# - #f) # kth,s(T) where (p is the porosity of the formation, (pf is the instantaneous fluid porosity, kh, i is the thermal conductivity of phase i = (w, o, g) = (water, oil, gas), S ; is the saturation of phase i = (w, o, g) = (water, oil, gas), k, » r (T) iS the thermal conductivity of rock (inert mineral matter), and kr,,, s (T) is the thermal conductivity of solid-phase components.

In some embodiments, a model may take into account the effect of different geological strata on properties of the formation. For example, the thermal conductivity of a model of a tar sands formation may be calculated from EQN. 5: where kif ils the thermal conductivity of the fluid phase at porosity, k ; is the thermal conductivity of geological layer i, and ci is the compressibility of geological layer i.

In an embodiment, the volumetric heat capacity, pbCp, may also be modeled as a direct function of temperature. However, the volumetric heat capacity also depends on the composition of the formation material through the density, which is affected by temperature.

In one embodiment, properties of the formation may include one or more phases with one or more chemical components. For example, fluid phases may include water, oil, and gas. Solid phases may include mineral matter and organic matter. Each of the fluid phases in an in situ process may include a variety of chemical components such as hydrocarbons, H2, CO2, etc. The chemical components may be products of one or more chemical reactions, such as pyrolysis reactions, that occur in the formation. Some embodiments of a model of an in situ process may include modeling individual chemical components known to be present in a formation.

However, inclusion of chemical components in a model of an in situ process may be limited by available experimental composition and kinetic data for the components and numerical and solution time limitations.

In some embodiments, one or more chemical components may be modeled as a single component called a pseudo-component. In certain embodiments, the oil phase may be modeled by two volatile pseudo-components, a light oil and a heavy oil. The oil and at least some of the gas phase components are generated by pyrolysis of organic matter in the formation. The light oil and the heavy oil may be modeled as having an API gravity that is consistent with laboratory or experimental field data. For example, the light oil may have an API gravity of between about 20° and about 70° ard the heavy oil less than about 20°.

In some embodiments, hydrocarbon gases in a formation of one or more carbon numbers may be modeled as a single pseudo-component. In other embodiments, non-hydrocarbon gases and hydrocarbon gases may be modeled as a single component. For example, hydrocarbon gases between a carbon number of one to a carbon number of five and nitrogen and hydrogen sulfide may be modeled as a single component. In some embodiments, the multiple components modeled as a single component have relatively similar molecular weights.

A molecular weight of the hydrocarbon gas pseudo-component may be set such that the pseudo-component is similar to a hydrocarbon gas generated in a laboratory pyrolysis experiment at a specified pressure.

In some embodiments of an in situ process, the composition of the generated hydrocarbon gas may vary with pressure. As pressure increases, the ratio of a higher molecular weight component to a lower molecular component tends to increase. For example, as pressure increases, the ratio of hydrocarbon gases with carbon numbers between about three and about five to hydrocarbon gases with one and two carbon numbers tends to increase. Consequently, the molecular weight of the pseudo-component that models a mixture of component gases may vary with pressure.

TABLE 1 lists components in a model of in situ process in a coal formation according to one embodiment. Similarly, TABLE 2 lists components in a model of an in situ process in an oil shale formation according to an embodiment.

TABLE 1 CHEMICAL COMPONENTS IN A MODEL OF A COAL FORMATION. Component Phase MW H20 Aqueous 18.016 heavy oil Oil 291. 37 light oil Oil 155. 21 HCgas Gas 19. 512 H2 Gas 2. 016 CO2 Gas 44. 01 CO Gas 28. 01 Gas 28. 02 02 Gas 32.0 Coal Solid 15. 153 Coalbtm Solid 14.786 Prechar Solid 14.065 Char Solid 12. 72 TABLE 2 CHEMICAL COMPONENTS IN A MODEL OF AN OIL SHALE FORMATION. Component Phase MW H20 Aqueous 18.016 heavy oil Oil 317.96 light oil Oil 154. 11 HCgas Gas 26. 895 H2 Gas 2. 016 C02 Gas 44. 01 CO Gas 28. 01 Hydramin Solid 15. 153 Kerogen Solid 15.153 Prechar Solid 12.72

As shown in TABLE 1, the hydrocarbon gases produced by the pyrolysis of coal may be grouped into a pseudo-component, HCgas. The HCgas component may have critical properties intermediate between methane and ethane. Similarly, the pseudo-component, HCgas, generated from pyrolysis in an oil shale formation, as shown in TABLE 2, may have critical properties very close to those of ethane. For both coal and oil shale, the HCgas pseudo-components may model hydrocarbons between a carbon number of about one and a carbon number of about five. The molecular weight of the pseudo-component in TABLE 2 generally reflects the composition of the hydrocarbon gas that was generated in a laboratory experiment at a pressure of about 6.9 bars absolute.

In some embodiments, the solid phase in a formation may be modeled with one or more components.

For example, in a coal formation the components may include coal and char, as shown in TABLE 1. The components in a kerogen formation may include kerogen and a hydrated mineral phase (hydramin), as shown in TABLE 2. The hydrated mineral component may be included to model water and carbon dioxide generated in an oil shale formation at temperatures below a pyrolysis temperature of kerogen.

Kerogen may be the source of most or all of the hydrocarbon fluids generated by the pyrolysis. Kerogen may also be the source of some of the water and carbon dioxide that is generated at temperatures below a pyrolysis temperature.

In an embodiment, the solid phase model may also include one or more intermediate components that are artifacts of the reactions that model the pyrolysis. For example, a coal formation may include two intermediate components, coalbtm and prechar, as shown in TABLE 1. An oil shale formation may include at least one intermediate component, prechar, as shown in TABLE 2. The prechar solid-phase components may model carbon residue in a formation that may contain H2 and low molecular weight hydrocarbons. Coalbtm accounts for intermediate unpyrolyzed compounds that tend to appear and disappear during pyrolysis.

In one embodiment, a model of an in situ process may include one or more chemical reactions. A number of chemical reactions are known to occur in an in situ process for a hydrocarbon containing formation.

The chemical reactions may belong to one of several categories of reactions. The categories may include, but are not limited to, generation of pre-pyrolysis water and carbon dioxide, generation of hydrocarbons, coking and cracking of hydrocarbons, formation of synthesis gas, and combustion and oxidation of coke.

In one embodiment, the rate of change of the concentration of species X due to a chemical reaction, for example: (I) X-> products may be expressed in terms of a rate law: (II) d [X] /dt =-k [X] n Species X in the chemical reaction undergoes chemical transformation to the products. [X] is the concentration of species X, t is the time, k is the reaction rate constant, and n is the order of the reaction. k may be defined by the Arrhenius equation: (III) k = A exp [-Ea/RT where A is the frequency factor, Ea is the activation energy, R is the universal gas constant, and T is the temperature. Kinetic parameters, such as k, A, Erz and n, may be determined from experimental measurements.

A simulation method may include one or more rate laws for assessing the change in concentration of species in an in situ process as a function of time. Experimentally determined kinetic parameters for one or more chemical reactions may be used as input to the simulation method.

In some embodiments, the number and categories of reactions in a model of an in situ process may depend on the availability of experimental kinetic data and/or numerical limitations of a simulation method.

Generally, chemical reactions and kinetic parameters for a model may be chosen such that simulation results match or approximate quantitative and qualitative experimental trends.

In some embodiments, reactions that model the generation of pre-pyrolysis water and carbon dioxide account for the bound water, carbon dioxide, and carbon monoxide generated in a temperature range below a pyrolysis temperature. For example, pre-pyrolysis water may be generated from hydrated mineral matter. In one embodiment, the temperature range may be between about 100 °C and about 270 °C. In other embodiments, the temperature range may be between about 80 °C and about 300 °C.

In an embodiment, the pressure dependence of the chemical reactions may be modeled. To account for the pressure dependence, a single reaction with variable stoichiometric coefficients may be used to model the generation of pre-pyrolysis fluids. Alternatively, the pressure dependence may be modeled with two or more reactions with pressure dependent kinetic parameters such as frequency factors. For example, experimental results indicate that the reaction that generates pre-pyrolysis fluids from oil shale is a function of pressure. In an embodiment, the generation of pre-pyrolysis fluids may be modeled with two reactions to account for the pressure

dependence. One reaction may be dominant at high pressures while the other may be prevalent at lower pressures. In one embodiment, a molar stoichiometry of two reactions may be written as follows: (6) 1 mol hydramin 0.5884 mol H20 + 0.0962 mol CO2 + 0.0114 mol CO (7) 1 mol hydramin 0.8234 mol H20 + 0. 0 mol CO2 + 0.0114 mol CO Experimentally determined kinetic parameters for Reactions (6) and (7) are shown in TABLE 3.

TABLE 3 shows that pressure dependence of Reactions (6) and (7) is taken into account by the frequency factor.

The values of the frequency-factor in TABLE 3 indicate that Reaction (6) dominates at high pressures while Reaction (7) dominates at low pressures.

In one embodiment, a reaction enthalpy may be used by a simulation method such as STARS to assess the thermodynamic properties of a formation. In TABLES 3-8, the reaction enthalpy is negative for an endothermic reaction and positive for an exothermic reaction.

TABLE 3 KINETIC PARAMETERS OF PRE-PYROLYSIS FLUID GENERATION REACTIONS IN AN OIL SHALE FORMATION. Pressure Frequency Activation Energy Reaction Enthalpy Reaction (bars Factor [(day) ~ Order absolute) absolute) ] 1. 0342 1. 197 x 109 4. 482 7. 938 x 10'° 7. 929 2. 170 x 10" 6 125, 600 1 0 11.376 4.353 x 1011 14. 824 7. 545 x 10" 18. 271 1. 197 x 1012 1. 0342 1. 197 x 1012 4. 482 5. 176 x 10" 7. 929 2. 037 x 10" 7 125,600 1 0 11.376 6.941 x 10'0 14. 824 1. 810 x 10'0 18. 271 1. 197 x 109 In other embodiments, the generation of hydrocarbons in a pyrolysis temperature range in a formation may be modeled with one or more reactions. One or more reactions may model the amount of hydrocarbon fluids and carbon residue that are generated in a pyrolysis temperature range. Hydrocarbons generated may include light oil, heavy oil, and non-condensable gases. Pyrolysis reactions may also generate water, H2, and CO2.

Experimental results indicate that the composition of products generated in a pyrolysis temperature range may depend on operating conditions such as pressure. For example, the production rate of hydrocarbons generally decreases with pressure. In addition, the amount of produced hydrogen gas generally decreases

substantially with pressure, the amount of carbon residue generally increases with pressure, and the amount of condensable hydrocarbons generally decreases with pressure. Furthermore, the amount of non-condensable hydrocarbons generally increases with pressure such that the sum of condensable hydrocarbons and non- condensable hydrocarbons generally remains approximately constant with a change in pressure. In addition, the API gravity of the generated hydrocarbons increases with pressure.

In an embodiment, the generation of hydrocarbons in a pyrolysis temperature range in an oil shale formation may be modeled with two reactions, one dominant at high pressures, the other at low pressures. For example, the reactions may be: (8) 1 mol kerogen + 0.02691 mol H2O + 0.009588 mol heavy oil + 0.01780 mol light oil + 0.04475 mol HCgas + 0.01049 mol H2 + 0.00541 mol CO2 + 0.5827 mol prechar (9) 1 mol kerogen # 0.02691 mol H20 + 0.009588 mol heavy oil + 0.01780 mol light oil + 0.04475 mol HCgas + 0.07930 mol H2 + 0. 00541 mol CO2 + 0.5718 mol prechar Experimentally determined kinetic parameters are shown in TABLE 4. Reactions (8) and (9) model the pressure dependence of hydrogen and carbon residue on pressure. However, the reactions do not take into account the pressure dependence of hydrocarbon production. In one embodiment, the pressure dependence of the production of hydrocarbons may be taken into account with or without a set of cracking/coking reactions.

TABLE 4 KINETIC PARAMETERS OF PRE-PYROLYSIS GENERATION REACTIONS IN AN OIL SHALE FORMATION. Pressure Frequency Activation Energy Reaction Enthalpy Reaction (bars Factor [ (day) Order absolue) absolute) ] 1. 0342 1. 000 x 109 4. 482 2. 620 x 1012 7. 929 2. 610 x 1012 8 161600 1 0 11.376 1.975 x 1012 14. 824 1. 620 x 1012 18. 271 1. 317 x 1012 1. 0342 4. 935 x 1012 4. 482 1. 195 x 1012 7. 929 2. 940 x 10" 9 161600 1 0 11. 376 7.250 x lOlo 14. 824 1. 840 x 10'0 18.217 1.100 # 1010

In one embodiment, one or more reactions may model the cracking and coking in a formation. Cracking reactions involve the reaction of condensable hydrocarbons (e. g. , light oil and heavy oil) to form lighter compounds (e. g. , light oil and non-condensable gases) and carbon residue. The coking reactions model the polymerization and condensation of hydrocarbon molecules. Coking reactions lead to formation of char, lower molecular weight hydrocarbons, and hydrogen. Gaseous hydrocarbons may undergo coking reactions to form carbon residue and H2. Coking and cracking may account for the deposition of coke in the vicinity of heater wells where the temperature may be substantially greater than a pyrolysis temperature. For example, the molar stoichiometry of the cracking and coking reactions in an oil shale formation according to one embodiment may be as follows: (10) 1 mol heavy oil (gas phase) # 1.8530 mol light oil + 0.045 mol HCgas + 2.4515 mol prechar (11) 1 mol light oil (gas phase) + 5.730 mol HCgas (12) 1 mol heavy oil (liquid phase) # 0.2063 mol light oil + 2.365 mol HCgas + 17.497 mol prechar (13) 1 mol light oil (liquidphase) 0. 5730 mol HCgas + 10.904 mol prechar (14) 1 mol HCgas + 2. 8 mol H2 + 1.6706 mol char Kinetics parameters for Reactions 10 to 14 are listed in TABLE 5. The kinetics parameters of the cracking reactions were chosen to match or approximate the oil and gas production observed in laboratory experiments. The kinetics parameter of the coking reaction was derived from experimental data on pyrolysis reactions in a coal experiment.

TABLE 5 KINETIC PARAMETERS OF CRACKING AND COKING REACTIONS IN AN OIL SHALE FORMATION. Pressure Frequency Activation Energy Reaction Enthalpy Reaction (bars Factor [(day)- Order (KJ/kgmole) (KJ/kgmole) absolute) 1.0342 4.482 7. 929 6. 250 x 1016 10 206034 1 0 11.376 14.824 18. 271 7. 950 x 1016 1.0342 4.482 7. 929 9. 850 x 1016 11 219328 1 0 11.376 14.824 18. 271 5. 850 x 1016 12 2. 647 x 102° 206034 _ 0 Pressure Frequency Activation Energy Reaction Enthalpy Reaction (bars Factor [ (day) Order (KJ/kgmole) (KJ/kgmole) absolute) 1] 13 - 3.820 # 1020 219328 1 0 14 7. 660 x 102° 311432 1 0

In addition, reactions may model the generation of water at a temperature below or within a pyrolysis temperature range and the generation of hydrocarbons at a temperature in a pyrolysis temperature range in a coal formation. In an embodiment, reactions may include: (15) 1 mol coal- 0.01894 mol H20 + 0.0004. 91 mol HCgas + 0.000047 mol H2 + 0.0006. 8 mol CO2 + 0.99883 mol coalbtm (16) 1 mol coalbtm 0.02553 mol H2O + 0.00136 mol heavy oil + 0.003174 mol light oil + 0.01618 mol HCgas + 0.0032 mol H2 + 0.005599 mol CO2 + 0.0008. 26 mol CO + 0.91306 mol prechar (17) 1 mol prechar # 0.02764 mol H20 + 0.05764 mol HCgas + 0.02823 mol H2 + 0.0154 mol CO2 + 0.006. 465 mol CO + 0.90598 mol char The kinetic parameters of the three reactions are tabulated in TABLE 6. Reaction (15) models the generation of water in a temperature range below a pyrolysis temperature. Reaction (16) models the generation of hydrocarbons, such as oil and gas, generated in a pyrolysis temperature range. Reaction (17) models gas generated at temperatures between about 370 °C and about 600 °C.

TABLE 6 KINETIC PARAMETERS OF REACTIONS IN A COAL FORMATION. Frequency Factor Frequency Factor Activation Energy Reaction Enthalpy Reaction (KJ/kgmole) (KJ/kgmole) (mole/m3)order-1] 15 2.069 # 1012 146535 5 0 16 1. 895 x1015 201549 1. 808-1282. 0 17 1. 64 x 102 230270 9 0 Coking and cracking in a coal formation may be modeled by one or more reactions in both the liquid phase and the gas phase. For example, the molar stoichiometry of two cracking reactions in the liquid and gas phase may be according to one embodiment: (18) 1 mol heavy oil 0.1879 mol light oil + 2.983 mol HCgas + 16.038 mol char (19) 1 mol light oil 0.7985 mol HCgas + 10.977 mol char In addition, coking in a coal formation may be modeled as

(20) 1 mol HCgas- 2.2 mol H2 + 1.1853 mol char Reaction (20) may model the coking of methane and ethane observed in field experiments when low carbon number hydrocarbon gases are injected into a hot coal formation.

The kinetic parameters of reactions 18-20 are tabulated in TABLE 7. The kinetic parameters for cracking were derived from literature data. The kinetic parameters for the coking reaction were derived from laboratory data on cracking.

TABLE 7 KINETIC PARAMETERS OF CRACKING AND COKING REACTIONS IN A COAL FORMATION. Frequency Factor Activation Energy Reaction Enthalpy Reaction Order (day)'' (KJ/kgmole) (KJ/kgmole) 18 2. 647 x 102° 206034 0 19 3. 82 x 102° 219328 1 0 20 7. 66 x 102° 311432 1 0

In certain embodiments, the generation of synthesis gas in a formation may be modeled by one or more reactions. For example, the molar stoichiometry of four synthesis gas reactions may be according to one embodiment: (21) 1 mol 0.9442 char + 1.0 mol CO2 @ 2.0 mol CO (22) 1. 0 mol CO + 0. 5 mol CO2+ 0.4721 mol char (23) 0.94426 mol char + 1.0 mol H2O + 1.0 mol H2 + 1. 0 mol CO (24) 1.0 mol H2 + 1.0 mol Cl @ 0.94426 mol char + 1.0 mol H20 The kinetic parameters of the four reactions are tabulated in TABLE 8. Kinetic parameters for Reactions 21-24 were based on literature data that were adjusted to fit the results of a coal cube laboratory experiment. Pressure dependence of reactions in the coal formation is not taken in to account in TABLES 6, 7 and 8. In one embodiment, pressure dependence of the reactions may be modeled with pressure dependent frequency-factors.

TABLE 8 KINETIC PARAMETERS FOR SYNTHESIS GAS REACTIONS IN A COAL FORMATION. Frequency Factor Activation Energy Reaction Enthalpy Reaction Order (day x bar)-1 (KJ/kgmole) (KJ/kgmole) 21 2. 47 x 10"169970 1-173033 22 201. 6 148. 6 1 86516 23 6. 44 x 1014 237015 1-135138 24 2. 73 x 1017 103191 1 135138 In one embodiment, a combustion and oxidation reaction of coke to carbon dioxide may be modeled in a formation. In an embodiment, the reaction may be: (25) 0.9442 mol char + 1. 0 mol O2 # 1.0 mol CO2

Experimentally derived kinetic parameters include a frequency factor of 1.0 x 104 (day)'', an activation energy of 58,614 KJ/kgmole, an order of 1, and a reaction enthalpy of 427,977 KJ/kgmole.

In some embodiments, a model of a tar sands formation may be modeled with the following components: bitumen (heavy oil), light oil, HCgas 1, HCgas2, water, char, and prechar. In one embodiment, an ICP in a tar sands formation may be modeled by: (26) 1.0 mol Bitumen @ 1.0 mol light oil + 1.0 mol HCgas 1 + 1.0 mol H20 + 1.0 mol prechar (27) 1.0 mol Prechar 1.0 mol HCgas2 + 1.0 mol H20 + 1.0 mol char Reaction (26) models the pyrolysis of bitumen to oil and gas components. In one embodiment, Reaction (26) may be modeled as a 2'"'order reaction and Reaction (27) may be modeled as a 7 order reaction. In one embodiment, the reaction enthalpy of Reactions (26) and (27) may be zero.

In an embodiment, a method of modeling an in situ process of treating a hydrocarbon containing formation using a computer system may include simulating a heat input rate to the formation from two or more heat sources. A body-fitted finite difference simulation method may be used to simulate a heat input rate from two or more heat sources in the formation. In one embodiment, the heat sources may be simulated with a model of heat sources with symmetry boundary conditions. The method may further include controlling the heat input rate from the heat sources (or some other process parameter) to achieve at least one desired parameter, such as a maximum temperature at specific locations, a desired heating rate, and/or a desired product composition. A maximum temperature may correspond to a maximum operating temperature for the metallurgy in the heater well, e. g. , between about 600 °C and about 700 °C.

FIG. 4 illustrates a model for simulating a heat transfer rate in a formation. Model 122 represents an aerial view of 1/12"'of a seven spot heater pattern. The pattern is composed of body-fitted grid elements 124.

The model includes horizontal heater 126 and producer 128. A pattern of heaters may be modeled with symmetry boundary conditions.

In one embodiment, an in situ process may be modeled with more than one simulation method. In certain embodiments, a first simulation method (e. g. , a body-fitted finite difference simulation method) may simulate heating of the formation, for example, heating the wellbore and the near wellbore region. Simulation of heating of the formation may assess (i. e. , estimate, calculate, or determine) heat injection rate data for the formation.

Heat injection rate data assessed by the first simulation method may be used as input into a second simulation method such as a space-fitted finite difference simulation. In some embodiments, heat injection rate data may be modified or altered (e. g. , as a boundary condition) for input into the second simulation method. The second simulation method may assess at least one process characteristic based on heat injection rate data and at least one property. In some embodiments, the first and the second simulation method may be used to predict process characteristics using parameters based on laboratory data.

In certain embodiments, the properties may change during a simulation using the second simulation method. Consequently, the heat input rate assessed by the first simulation method may not be an adequate boundary condition to achieve a desired parameter of the process. In an embodiment, the method may include assessing modified heat injection rate data from the first simulation method at a specified time of the second simulation.

In some embodiments, one or more model parameters for input into a simulation method may be based on laboratory or field test data of an in situ process for treating a hydrocarbon containing formation. In an embodiment, model parameters may be calibrated to match or approximate laboratory or field data for an in situ process. In certain embodiments, a simulation method based on a set of model parameters may be used to design an in situ process. A field test of the design may be used to calibrate the model parameters.

In one embodiment, simulations of an in situ process for treating a hydrocarbon containing formation may be used to design and/or control a real in situ process. Design and/or control of an in situ process may include assessing at least one operating condition that achieves a desired parameter of the in situ process. FIG. 5 illustrates a flowchart of an embodiment of method 130 for the design and/or control of an in situ process. The method may include providing to the computer system one or more values of at least one operating condition 132 of the in situ process for use as input to simulation method 120.

In one embodiment, the method may include assessing one or more values of at least one process characteristic 134 corresponding to one or more values of at least one operating condition 132 from one or more simulations using simulation method 120. A desired value of at least one process characteristic 136 for the in situ process may also be provided to the computer system. An embodiment of the method may further include assessing 138 desired value of at least one operating condition 140 to achieve the desired value of at least one process characteristic 136. The desired value of at least one operating condition 140 may be assessed from the values of at least one process characteristic 134 and values of at least one operating condition 132. For example, desired value 140 may be obtained by interpolation of values 134 and values 132. In some embodiments, a value of at least one process characteristic may be assessed from the desired value of at least one operating condition 140 using simulation method 120. In an embodiment, the method may include operating the in situ system using the desired value of at least one operating condition.

In an embodiment, a desired value of at least one operating condition to achieve a desired value of at least one process characteristic may be assessed by using a relationship (e. g. , tabulated values stored on a database and/or an analytical function) obtained from simulation between at least one process characteristic and at least one operating condition of the in situ process.

In one embodiment, a simulation method on a computer system may be used in a method for modeling one or more stages of a process for treating a hydrocarbon containing formation in situ. The one or more stages may include a heating stage, a pyrolyzation stage, a synthesis gas generation stage, a remediation stage, and/or a shut-in stage.

Changes in physical and mechanical properties due to treatment of a formation may result in deformation of the formation. Deformation characteristics may include, but are not limited to, subsidence, compaction, heave, and shear deformation. Heave is a vertical increase at the surface above a treated portion of a formation.

Subsidence is a downward movement of a portion of a formation relative to an initial elevation of the surface.

In certain embodiments, an in situ treatment process may be designed and controlled such that deformation is minimized or substantially eliminated. FIG. 6 illustrates a flowchart of an embodiment of method 142 for modeling deformation due to in situ treatment of a hydrocarbon containing formation. The method may include providing properties 114 of the formation to a computer system. Properties may include, but are not limited to, mechanical, chemical, thermal, and physical properties of the portions of the formation. In addition, at least one operating condition 116 may be provided to the computer system. In some embodiments, physical

and mechanical properties for a model of a formation may be assessed from samples extracted from a geological formation targeted for treatment.

In an embodiment, assessing deformation using a simulation method may use a material or constitutive model. A constitutive model relates the stress in the formation to the strain or displacement. Mechanical properties may be entered into a constitutive model to calculate the deformation of the formation. In some embodiments, the Drucker-Prager-with-cap material model may be used to model the time-independent deformation of the formation.

The method shown in FIG. 6 may further include assessing 138 at least one process characteristic 118 of the treated portion of the formation. At least one process characteristic 118 may be, but is not limited to, a pore pressure distribution, a heat input rate, or a time dependent temperature distribution in the treated portion of the formation. At least one process characteristic may be assessed by a simulation method. For example, a heat input rate may be estimated using a body-fitted finite difference simulation package such as FLUENT. Similarly, the pore pressure distribution may be assessed from a space-fitted or body-fitted simulation method such as STARS. In other embodiments, the pore pressure may be assessed by a finite element simulation method such as ABAQUS (where ABAQUS is from Hibbitt, Karlsson & Sorensen, Inc. located in Pawtucket, Rhode Island). ABAQUS is a finite element simulation method for calculating elastic, plastic, and time dependent behavior of materials.

Alternatively, temperature and pore pressure distributions may be approximated by imposing average boundary conditions in the calculation of deformation characteristics.

In some embodiments, the method may include assessing at least one deformation characteristic 144 of the formation using simulation method 120 on the computer system as a function of time. In some embodiments, at least one deformation characteristic may be assessed from properties 114, at least one process characteristic 118, and at least one operating condition 116. In some embodiments, process characteristic 118 may be measured.

Computer simulations may be used to assess operating conditions of an in situ process in a formation that result in desired deformation characteristics. In one embodiment, a simulation method may be used for designing and controlling an in situ process.

In certain embodiments, a computer system may be used to operate an in situ process for treating a hydrocarbon containing formation. The in situ process may include providing heat from heat sources to at least one portion of the formation. The heat may transfer from the heat sources to a selected section of the formation.

FIG. 7 illustrates method 146 for operating an in situ process using a computer system. The method may include operating in situ process 148 using one or more operating parameters. Operating parameters may include, but are not limited to, properties of the formation, operating conditions, and/or deformation characteristics.

In certain embodiments, at least one operating parameter 150 of in situ process 148 may be provided to computer system 152. Computer system 152 may be at or near in situ process 148. Alternatively, computer system 152 may be at a location remote from in situ process 148. The computer system may include a first simulation method for simulating a model of in situ process 148. In one embodiment, the first simulation method may include, method 112 illustrated in FIG. 3, and/or method 130 illustrated in FIG. 5. The first simulation method may perform a reservoir simulation that determines operating parameters. In an embodiment, the first simulation method may also calculate deformation in a formation. A simulation method for calculating deformation characteristics may include method 142 illustrated in FIG. 6.

Method 146 may include using at least one parameter 150 with a first simulation method and the computer system to provide assessed information 154 about in situ process 148. Simulated operating parameters may be compared to operating parameters of in situ process 148. Assessed information from a simulation may include a simulated relationship between one or more operating parameters with at least one parameter 150.

In some embodiments, assessed information may include inconsistencies between operating parameters from simulation and operating parameters from in situ process 148. For example, the temperature, pressure, product quality, or production rate from the first simulation method may differ from in situ process 148. The source of the inconsistencies may be assessed from the operating parameters provided by simulation. The source of the inconsistencies may include differences between certain properties used in a simulated model of in situ process 148 and in situ process 148.

In one embodiment, assessed information may include adjustments in one or more operating parameters of in situ process 148. The adjustments may compensate for inconsistencies between simulated operating parameters and operating parameters from in situ process 148. Adjustments may be assessed from a simulated relationship between at least one parameter 150 and one or more operating parameters.

In some embodiments, method 146 may include using assessed information 154 to operate in situ process 148. As used herein, "operate"refers to controlling or changing operating conditions of an in situ process.

In some embodiments, method 146 may include obtaining 156 information 158 from a second simulation method and the computer system using assessed information 154 and desired parameter 160. In one embodiment, the first simulation method may be the same as the second simulation method. In another embodiment, the first and second simulation methods may be different. Simulations may provide a relationship between at least one operating parameter and at least one other parameter. Additionally, obtained information 158 may be used to operate in situ process 148. Obtained information 158 may include at least one operating parameter for use in the in situ process that achieves the desired parameter. In one embodiment, simulation method 130 illustrated in FIG. 5 may be used to obtain at least one operating parameter that achieves the desired parameter. For example, a desired hydrocarbon fluid production rate for an in situ process may be 6 m3/day. One or more simulations may be used to determine the operating parameters necessary to achieve a hydrocarbon fluid production rate of 6 m3/day. In some embodiments, model parameters used by simulation method 120 may be calibrated to account for differences observed between simulations and in situ process 148.

FIG. 8 illustrates a schematic of an embodiment for controlling in situ process 148 in a formation using a computer simulation method. In situ process 148 may include sensor 162 for monitoring operating parameters.

Sensor 162 may be located in a barrier well, a monitoring well, a production well, or a heater well. Sensor 162 may monitor operating parameters such as subsurface conditions in the formation. Some sensors 162 may monitor surface data. Surface data may be monitored with instruments placed at a well.

At least one operating parameter 150 measured by sensor 162 may be provided to local computer system 164. In some embodiments, operating parameter 150 may be provided to remote computer system 385. FIG. 9 illustrates several ways that information such as an operating parameter or operating parameters may be transmitted from in situ process 148 to remote computer system 385. Information may be transmitted by means of internet 168 or local area network, hardwire telephone lines 170, and/or wireless communications 172. In some embodiments, information may be sent by satellite 174. Information may be received at an in situ process

site by internet or local area network, hardwire telephone lines, wireless communications, and/or satellite communication systems.

Operating parameter 150 may be provided to computer system 164 or 385 automatically during the treatment of a formation, as depicted in FIG. 8. Computer systems 385 and 164 may include a simulation method for simulating a model of the in situ treatment process 148. The simulation method may be used to obtain information 158 about the in situ process. In an embodiment, a simulation of in situ process 148 may be performed manually at a desired time or automatically when a desired condition is met.

In some embodiments, information 158 relating to in situ process 148 may be provided automatically by computer system 166 or 164 for use in controlling in situ process 148. Information 158 may include instructions relating to control of in situ process 148. Information 158 may be provided to computer system 178. In some embodiments, computer system 178 may be at a location remote from the in situ process. Computer system 178 may process information 158 for use in controlling in situ process 148. For example, computer system 178 may use information 158 to determine adjustments in one or more operating parameters. Computer system 178 may then automatically adjust 180 one or more operating parameters of in situ process 148. Alternatively, one or more operating parameters of in situ process 148 may be displayed and/or manually adjusted 182.

FIG. 10 illustrates a schematic of an embodiment for controlling in situ process 148 in a formation using information 158. Information 158 may be obtained using a simulation method and a computer system.

Information 158 may be provided to computer system 178. Information 158 may include information that relates to adjusting one or more operating parameters. Output 184 from computer system 178 may be provided to display 186, data storage 188, and/or surface facility 108. Output 184 may be used to automatically control conditions in the formation by adjusting one or more operating parameters. Output 184 may include instructions to adjust pump status and/or flow rate at a barrier well 110, instructions to control flow rate at a production well 104, and/or adjust heater power at a heater well 194. Output 184 may include instructions to heating pattern 190 of in situ process 148. In some situations, output 184 may include instructions to shut-in the formation 192. In some embodiments, output 184 may be viewed by operators of the in situ process on display 186. The operators may use output 184 to manually adjust one or more operating parameters.

FIG. 11 illustrates a schematic of an embodiment for controlling in situ process 148 in a formation using a simulation method and a computer system. At least one operating parameter 150 from in situ process 148 may be provided to computer system 152. Computer system 152 may include a simulation method for simulating a model of in situ process 148. Computer system 152 may use the simulation method to obtain information 158 about in situ process 148. Information 158 may be provided to data storage 188, display 186, and/or analyzer 196. In an embodiment, information 158 may be automatically provided to in situ process 148. Information 158 may then be used to operate in situ process 148.

Analyzer 196 may review and organize information 158 and/or use the information to operate in situ process 148. Analyzer 196 may obtain additional information 198 from one or more simulations 200 of in situ process 148. One or more simulations may be used to obtain additional or modified model parameters of in situ process 148. The additional or modified model parameters may be used to further assess in situ process 148. A method may use at least one operating parameter 150 and information 158 to calibrate model parameters. For example, at least one operating parameter 150 may be compared to at least one simulated operating parameter.

Model parameters may be modified such that at least one simulated operating parameter matches or approximates at least one operating parameter 150.

In an embodiment, analyzer 196 may obtain 156 additional information 202 about properties of in situ process 148. Properties may be obtained from the literature, or from field or laboratory experiments. Additional information 202 may be used to operate in situ process 148. In some embodiments, output from analyzer 196 may be used in one or more simulations 200 to obtain additional information 198. For example, additional information 198 may include one or more operating parameters that may be used to operate in situ process 148.

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.